This comment letter response contains two parts:   

(1) The original submittal from the commenter.

(2) A data base printout of EPA’s response to each point raised by the commenter.

Notes about the response letters:

• The response letters were generated by a data base used to track the content of all public

comment submittals and ensure that the Agency responds to each. Each comment letter

was assigned a Letter ID that corresponds to the last four digits of the docket number of the

original comment (as posted on www.regulations.gov).

• Each response letter includes: comment text; an EPA‐assigned comment code; and an

individual response. These are described and explained below.  

• The data base contains Comment text from the letters submitted by commenters.  

Many hard copy letters were scanned into electronic format for inclusion in the data

base. As a result, there may be some typographical errors attributable to optical

character recognition issues.  However, all original submittals were reviewed in the

process of drafting responses to ensure that the comment content was understood and

appropriately addressed.

• The content of each comment letter was divided into topic areas and assigned a unique

Comment ID.  Additionally, one or more Comment Codes (i.e., unique topic area ID) was

assigned to each discrete point raised by a commenter. This information was added to

the data base. To inform final rulemaking decisions, all comments and information

received on a given topic were reviewed by technical experts in each rule area (e.g., on

construction requirements).  

• Following decisions on the final rule requirements, Individual responses were drafted

by topic area to ensure completeness and consistency of the responses with the final

rule and other responses to similar comments.  Each discrete point made by a

commenter was given a unique response.

• Upon completion of comment responses, all information was entered into the data base.

Each letter response is a compilation of each comment and its individual response,

compiled in the order of the original comment letter.  As a result of this process, there is

repetition in the response text.  The Agency believes this approach ensures completeness

and attention to each comment letter that was submitted.   

• All comments in a topic area were reviewed, evaluated, and responded to concurrently.  

Responses on each topic area are compiled and are also available in the rulemaking docket.
December 23, 2008 

Ms Cynthia Dougherty 

Director, Office of Ground Water and Drinking Water 

US Environmental Protection Agency 

1400 Pennsylvania Ave 

Washington D.C. 20002 

Dear Ms Dougherty, 

The following is submitted in response to: Federal Requirements Under the 

Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic 

Sequestration (GS) Wells; Proposed Rule (Docket ID No. EPA-HQ-OW-2008-0390) 

 On behalf of the Board of Directors and member states of the Ground Water Protection 

Council, (GWPC), I am pleased to transmit the attached documents in response to the 

United States Environmental Protection Agency’s request for comments on its Proposed 

Rule for carbon capture and storage (CCS). Our submittal contains three parts: 

1) Official comments reviewed and adopted by the GWPC Board of Directors: 

GWPC Recommendations to USEPA on Proposed CO2 UIC Rule Final 12-23-08 

2) Technical comments, prepared by the GWPC CO2 Committee of 12 experts with 

substantial educational and technical experience representing a diverse group of 

interests and backgrounds: 

CO2 Committee Response to USEPA on Notice Questions Final 12-23-08 

3) A Resolution Regarding Delegation of Primary Enforcement Authority to States 

For The Geo-sequestration of Carbon Dioxide, adopted by the GWPC Board of 

Directors that strongly supports full program delegation of Class VI wells and the 

option for partial primacy as well. 
The GWPC committed hundreds of hours of technical discussions, both at scheduled 

meetings and also within its CO2 Committee meetings. The technical comments provided 

as a result, represent a significant cross cut of state oil and gas, and public water supply 

agencies, environmental associations, national labs, universities, producing and service 

companies. At GWPC meetings there were multiple presentations made on the issues and 

a broad opportunity for public comment and participation was made available. 

GWPC member states and individual participants made numerous comments throughout 

this Rule development process commending the USEPA Office of Ground Water and 

Drinking Water on providing opportunity for comment and the extent to which the 

OGWDW went to insure that a wide variety of experts and views were involved in the 

process. We wish to thank them for these exceptional efforts. 

The GWPC is the only national association wherein a body of expertise on the technical 

and regulatory aspect of all types of underground injection control wells exists. We 

believe that our mission to protect and conserve ground water for all beneficial uses 

coupled with our commitment to applying sound science in efforts such as this, creates a 

strong basis for these comments and future Rule development. If you should desire any 

additional information on any of the submitted documents, please don’t hesitate to 

contact us. 

Respectfully Submitted 

Michel J Paque 

Secretary and Executive Director 
RESOLUTION 08-1 

REGARDING DELEGATION OF PRIMARY ENFORCEMENT AUTHORITY TO STATES FOR THE 

GEOSEQUESTRATION OF CARBON DIOXIDE 

WHEREAS, the United States Environmental Protection Agency (USEPA) has determined the geologic sequestration 

of carbon dioxide is a process that falls within the jurisdiction of the Safe Drinking Water Act (SDWA), Underground 

Injection Control (UIC) program; and 

WHEREAS, the USEPA has developed a proposed federal rule under the UIC program to regulate the practice of 

geologic sequestration of carbon dioxide; and 

WHEREAS, the USEPA has proposed the creation of a new injection well class for carbon dioxide geologic 

sequestration injection wells with the designation of Class VI; and 

WHEREAS, upon adoption of a federal rule states will lack primacy enforcement authority (Primacy) for Class VI 

wells until such authority is delegated to the states by USEPA; and 

WHEREAS, the USEPA has indicated the delegation of primacy for Class VI wells will fall under the authority of 

Section 1422 of the SDWA; and 

WHEREAS, it is the current practice of USEPA to only delegate primacy under Section 1422 of the SDWA if a state 

accepts primacy for all well classes other than Class II wells; and 

WHEREAS, it is in the best interest of protecting ground water resources for the geologic sequestration of carbon 

dioxide to be regulated at the state level; and 

WHEREAS, the GWPC is an association of state administrators of underground injection control and ground water 

protection programs that will be responsible for administering programs for the geologic sequestration of carbon 

dioxide; and 

WHEREAS, any requirement by USEPA that states accept primacy for Class I, III, IV and V wells, as a condition for 

obtaining primacy for Class VI wells will create an unreasonable burden upon states; and 

WHEREAS, any requirement by USEPA that states with primacy for Class I, III, IV and V wells also accept primacy 

for Class VI wells will compromise the states ability to decide how best to administer the states UIC program and may 

unnecessarily disrupt the states’ UIC program; 

NOW THEREFORE BE IT RESOLVED THAT, the GWPC recommends USEPA provide for the voluntary and 

separate delegation of primacy to the states for Class VI wells under the UIC program unless the state requests the 

delegation be made a part of a state UIC primacy program. 

 

Passed by the Board 

 

Attest 

Michel J. Paque, Secretary 
1 

335843.5 

GWPC CO2 Committee Responses to EPA Notice Questions 

EPA Notice 

Questions EPA Rule Issue GWPC CO2 Committee Response 

73 FR 43504 8. Class VI requirements and permits 

will need to be carefully structured to ensure that they do not “authorize” inappropriate hazardous releases. This would include clarifying if there are potential releases from the well which are outside the scope of the Class VI permit. EPA requests comment on particular situations where this might occur. EPA notice 43504. 

CERCLA application should be avoided or sorted out and affirmed by Congress to indicate that it would not apply; municipal operators have major concern over this potential because cities will be around long-term and look like deep pockets 

As EPA has noted, CERCLA liability does not apply 

to federally permitted releases (FPRs), including releases covered by a UIC permit, even if GS would lead to a hazardous substance release. Nor should CERCLA liability apply to any downstream reactions or transformations resulting from FPRs. 

Accordingly, there appears to be little real potential 

for CERCLA liability resulting from GS. Yet EPA needs to clarify that CERCLA liability is extremely unlikely to result from any GS operation that has not injected streams that are not covered by its UIC permit. 

Even the pote

with such aoverwhelmingly has had on ththat EPA’s dissubstantial clachilling effect odeployment of 

73 FR 43504 9. EPA also requests comment on 

other considerations associated with the presence of impurities in the CO2 stream related to CERCLA. EPA Notice 43504. 

The only need is to address constituents in a CO2 stream that would defeat capture, compression, transport or GS, and these can be addressed through the use of special materials in many cases. The focus should be on compatibility rather than on any need for purification. 

73 FR 43506 10. EPA’s proposal would provide the 

Director the discretion to require the owner or operator to identify and characterize 

Any showing of secondary containment is 

unnecessary once the requirement for containment has been satisfied by providing for an adequate 

Any emphasis 

confining zonethe adequacy 
GWPC CO2 Committee Response 2 

EPA Notice 

Questions EPA Rule Issue GWPC CO2 Committee Response 

additional confining and containment zones above the primary (i.e., lowermost) confining zone that could further impede vertical fluid movement and allow for pressure dissipation. EPA says that these layers could provide additional sites for monitoring, mitigation, and remediation. EPA’s proposal would not require that these additional zones be identified for all GS sites because their absence does not necessarily indicate inappropriateness of a GS site. However, if such zones are present, information about their characteristics can provide inputs for predictive models, identify appropriate monitoring locations, and improve public confidence in and acceptance of a proposed GS site. EPA specifically seeks comment on the merits of requiring the identification of these additional zones. EPA Notice 43506. 

confining zone. References to additional confining and containment zones is more likely to lead to confusion than support. 

requirements bdefinition reduprotection. Mconfining zonebeneficially any of interest cove

73 FR 43512 25. EPA is also requesting comments 

on whether aquifer exemptions should be allowed for the purpose of Class VI injection, and under what conditions should such aquifer exemptions be approved. EPA Notice 43512. 

The committee recommends that aquifeexemptions be allowed. 

r 

At this time, the Committee 

is not recommending any specific need for new aquifer exemption criteria created because the existing criteria are perceived to be sufficient to allow aquifer exemptions as needed for GS. Even without changes, the aquifer exemption requirements in the UIC program would allow operators to obtain appropriate exemptions for GS operations. 

73 FR 43512 26. EPA seeks comment on whether 

the Agency should set a minimum injection depth requirement for CO2 GS, rather than require that such injection take place below the lowermost USDW. EPA Notice 43512. 

There should not be a minimum depth established AND there should be no blanket restriction concerning proximity to USDWs but should instead be based on ability to protect USDWs. 

The presence above demonformations at fluids compara
GWPC CO2 Committee Response 3 

EPA Notice 

Questions EPA Rule Issue GWPC CO2 Committee Response 

73 FR 43513-15 27. EPA’s proposal allows Directors’ 

discretion on whether to require the use of tracers, and if so, what types of tracers. EPA seeks comment on the use of tracers in CO2 GS operations, and any potential impact of tracers on human health or ecosystems as they relate to USDWs. EPA Notice 43513. 

Due to the knowledge gaps in the use of tracers in this type of environment language regarding Directors discretion is OK. However, further research needs to be conducted before any finallanguage to allow the use of tracers is approved. 

73 FR 43517 33. EPA seeks comment on the 

appropriate amount and types of monitoring that should be conducted at a GS site. Specifically, EPA seeks comment regarding the usefulness of indirect geophysicalmonitoring and surface air and soil gas monitoring. In addition, EPA seeks comment regarding the use of a Directorapproved monitoring plan for GS sites. EPA Notice 43517. 

Although actual monitoring of injection formationmight be considered most effective you still have the potential problem of putting holes in the confining formation. Perhaps the use of seismic to place monitoring wells into the injection zone would be an appropriate approach. The number of monitoring wells should not be established in advance. Obviously the UIC program does not have complete control over monitoring well construction or operation or closure. With respect to soil and air monitoring there is a question as to the efficacy of these as a means of protecting USDWs. 

73 FR 43518 37. In addition to the above 

recordkeeping and reporting requirements, EPA considered a requirement for owners or operators of GS sites to provide an annual report during the lifetime of the project, including the post-injection period, regarding the GS operation. Although EPA has not included a requirement for this report in its proposal, EPA seeks comment regarding the necessity for such an annual report. EPA Notice 43518. 

See Workgroup recommendation 7.6 for further details. Report annually, or at a frequency acceptable to the Director, the characteristics and cumulative volumes (annual and total) of injected fluids, injection pressures, injection rates, annular pressures for each injection well, the results of any mechanical integrity tests conducted during this time period, available site integrity monitoring results, the extent of the injected CO2 and the pressure front based on current data. Update site operations as appropriate and site modeling results annually, or at a frequency acceptable to the Director, to reflect current data. Compare the updated results to the previous 
GWPC CO2 Committee Response 4 

EPA Notice 

Questions EPA Rule Issue GWPC CO2 Committee Response 

results. Identify and explain to the Director any discrepancies between the updated results and the previous results. Note: Technology transfer is a better forum for driving regulatory changes. Do not support annual reporting as outlined in the preamble. 
GWPC CO2 Committee Response 5 

EPA Notice 

Questions EPA Rule Issue GWPC CO2 Committee Response 

73 FR 43519-20 146.93(b) 

38. EPA is proposing using a combination of fixed timeframe and a performance standard as described above. EPA is tentatively proposing a post-injection site care (monitoring) period of 50 years with Director’s discretion to change that period to lengthen or shorten the 50 year period if appropriate. EPA requests comment on the proposed use of a tentative 50 year fixed timeframe that could be modified at the Director’s discretion based on monitoring and modeling data. EPA Notice 43519. 

It is inappropriate to utilize a fixed period. A demonstration of non endangerment is an appropriate means of deciding when monitoring is no longer needed. The Committee recommends using a combination of the non-endangerment standard with specific performance standards as follows: Prior to authorization for site closure, the owner or operator must demonstrate to the Director, based on monitoring, other site-specific data, and modeling that is reasonably consistent with site performance, that no additional monitoring is needed to assure that the geologic sequestration project does not and is not expected to pose an endangerment to USDWs. The Director shall approve closure if the owner or operator demonstrates, based on the current understanding of the site, including monitoring data and/or modeling, all of the following: (i) the estimated magnitude and extent of the project footprint (CO2 plume and the area of elevated pressure) ; (ii) the estimated location of the detectable CO2 plume; (iii) that there is no significant leakage of either CO2 or displaced formation fluids that is endangering USDWs; (iv) that the injected or displaced fluids are not expected to migrate in the future in a manner that encounters a potential leakage pathway into a USDW; (v) that the injection wells at the site completed into or through the injection zone or confining zone are plugged and abandoned in accordance with these requirements; and (vi) any remaining project monitoring wells at the site are being managed by a person and in a manner acceptable to the Director.

The fixed timeby scientific represents an use of performrecognized as other situationperformance sthe difficulties movement withimportant demmovement. 
GWPC CO2 Committee Response 6 

EPA Notice 

Questions EPA Rule Issue GWPC CO2 Committee Response 

144.36 41. Current UIC guidance describes 

trust funds as a form of financial assurance. The owner or operator may deposit funds into the trust fund in phases; that is, either over the term of the initial permit or over the remaining operating life of the injection well, as estimated in the well plugging plan, whichever period is shorter. Because of the possibility that the owner or operator may 

face financial distress prior to the trust being fully funded, EPA is considering a guidance approach that would recommend adopting a pay in period of three years for GS projects, consistent with other similar programs in the Agency. EPA Notice 43521. 

The Committee recommends that financial assurance requirements be based on costing of plans, with updating as appropriate to account for changed conditions and modified plans. The methods of providing FA should remain flexible, as EPA has proposed, to allow markets to adapt to the requirements and to identify methods for providing FA. Under any circumstances, EPA should continue to use self-insurance mechanisms through a financial test. Any development of guidance for specific FA instruments should await the initial experience with those instruments, but would probably be addressed better through guidance than regulations to maintain a greater amount of flexibility to adapt to changes in the market that are likely to follow increased understanding of the technologies involved and operating experience with those technologies. All FA requirements should be released at closure. 

For any particshould be comi.e. greater risk The plans shoconjunction wreevaluations operational emodeling. 

73 FR 43521 42. Current UIC regulations for Class I 

hazardous waste injection allow for the use of insurance for purposes of demonstrating financial responsibility. However, insurance was not included as part of the guidance provided for Class II injection because this insurance mechanism was and still is, rarely used for the purpose of demonstrating financial assurance for injection wells. EPA is assessing whether to provide guidance on the use of insurance providers and, if so, whether to update eligibility requirements for insurers for GS wells consistent with other current Federal agency practices. EPA Notice 43521. 

Leave the door open for establishing financials mechanisms on a project by project basis. The rulemaking should not prescribe or preclude particular financial instruments. The issue of financial assurance is complex and must be considered in significant detail and should be based on the initial experience gained from the use of FA mechanisms before any guidance or regulation is issued. 
GWPC CO2 Committee Response 7 

EPA Notice 

Questions EPA Rule Issue GWPC CO2 Committee Response 

73 FR 43522 43. EPA is assessing whether a 

financial ratings threshold for all companies using a self-guarantee, similar to those used by other Federal agencies, is appropriate. The Agency also is considering what constitutes an appropriate financial rating threshold, and whether a financial rating greater than BBB or Baa (i.e., the current rating threshold established under the UIC regulations) is appropriate for GS wells. EPA Notice 43522. 

See response to #41. 

146.85 44. EPA is requesting comments on 

whether financial responsibility mechanisms to be recommended in EPA guidance should be adjusted in the manner described, whether additional instruments should be included, and whether other adjustments to the financial responsibility mechanisms should be considered, all subject to EPA’s authority under the SDWA. EPA Notice 43522. 

See response to #41 

73 FR 43522 45. The Agency is also requesting 

comment on allowing separate financial demonstrations to be submitted for the plugging of the injection well and for the post-injection site care requirements. EPA Notice 43522. 

The Committee supports the use of separate financial demonstrations for the plugging of the injection well and for the post-injection site care requirements based on the greater experience with well plugging requirements and methods. It will be easier to retain certainty for these actions and to use established FA methods. 

EPA should losingle bonding bonding, as is 
GWPC CO2 Committee Response 8 

EPA Notice 

Questions EPA Rule Issue GWPC CO2 Committee Response 

73 FR 43523 46. EPA requests comment on 

adopting the existing requirements for public participation at 40 CFR Part 25 and 40 CFR Part 124 and whether additional requirements should be included to reflect the availability of new tools for disseminating and gathering information. Such tools include cable networks, the Internet, and other new technology. EPA Notice 43523. 

Public participation requirements for Class VI well permitting should follow established requirements for UIC program permitting, which have proven successful. Any modifications to account for technological advances should be considered on a program-wide basis; there is nothing unique about GS in this respect. 

73 FR 43522-23 47. EPA also requests comment on 

ways to enhance the public participation process, including engaging communities in the site characterization process as soon as candidate locations are identified. EPA Notice 43523. 

This is best left up to the discretion of the regulator. Establishing a process may provide a standard that can be followed by developers. There was concern about the term “as soon as”. If included, this term should be changed to a more reasonable period following applicant evaluation of a site. Public participation requirements should be similar to other portions of the UIC program (e.g. Class I). The program should assure a public hearings process when warranted by substantive issues and affected stakeholders but the timing and particulars of the process should not be prescribed in the rule. 

73 FR 43523 48. To gain authority for Class VI wells, 

States, Territories, and Tribes will be required to show that their regulations are at least as stringent as, and may be more stringent than, the proposed minimum Federal requirements (e.g., inspection, operation, monitoring, and recordkeeping requirements that well owners or operatorsmust meet). Such Primacy States, Territories, and Tribes are authorized under Section 1422 of the SDWA. EPA Notice 43523. 

Retain current requirement, but recognize that geology varies from state to state and some modifications may be appropriate that will result in variations that are not less stringent, but simply adapted to different circumstances. There should also be some recognition that the beneficial effects of GS may be enhanced by allowing flexibility for adaptation of state requirements. 
GWPC CO2 Committee Response 9 

EPA Notice 

Questions EPA Rule Issue GWPC CO2 Committee Response 

73 FR 43523 49. There may be benefits to parsing 

out primacy for Class VI wells, however EPA has not made a decision on this. 

Allowing States, Territories, and Tribes to 

acquire primacy for only Class VI wells may encourage them to assume the responsibility of implementation and provide for a more comprehensive approach to managing CCS projects (e.g., capture, transportation, and geologic sequestration). EPA is seeking comment on the merits and possible disadvantages of allowing primacy approval for Class VI wells independent of other well classes. EPA Notice 43523. 

Resolution 08-1 of the GWPC strongly urges USEPA to allow for the granting of individual primacy to states for the Class VI program. We further support the preservation of state authority to determine what agencies will exercise primacy, strongly urge USEPA to provide adequate funding, which will require a substantial increase above current funding levels both to meet both existingUIC program needs and the additional resources anticipated to be necessary for the Class VI program. Ramp up of resources, personnel, and training should precede anticipated heavy demand. 

Submit GWPC 

73 FR 43527 51. The Agency assumes three 

monitoring wells per injection well for the purpose of estimating national costs; however, the Agency recognizes that operators and primacy agency Directors may choose more or fewer monitoring wells depending on project site characteristics. Because the monitoring wells and associated costs represent a significant component of the Cost Analysis, the 

Agency acknowledges that this factor may 

be significant in the overall uncertainty of the Cost Analysis. EPA requests comment on whether three monitoring wells per injection well is an appropriate costing assumption. EPA Notice 43527. 

The group is unsure as to EPA’s methodology for deciding on the number of monitoring wells since each project could be vastly different requiring a wide variety in numbers and types of any necessary monitoring wells. Also, it was felt that the statement regarding the fact that monitoring wells are a significant portion of the costs has not been supported by independent analysis as yet. Therefore, the issue of numbers of monitoring wells is not yet ripe for a decision. There should not be a requirement for monitor wells into the injection zone, and monitor wells should not be required for the purpose of tracking the plume or pressure front. 

73 FR 43531 52. The public is invited to submit 

comments or identify peer-reviewed studies and data that assess the effects of early life exposure to changes in drinking water quality that may be caused by geologic sequestration of carbon dioxide. EPA Notice 43531. 

Studies already exist that address potential exposure issues, but there should be a recognition of the very low potential for exposure that exists for GS projects. 
GWPC CO2 Committee Response 10 
GWPC Recommendations Page 1 of 40 1 

Recommendations of the Ground Water Protection Council (GWPC) 

Rule Provision EPA Proposal GWPC Recommendations 

Part 144 1. The authority citation for part 144 

continues to read as follows: 

Authority: 42 U.S.C. 300f et seq.; Resource 

Conservation and Recovery Act, 42 U.S.C. 6901 et seq. 

No comment necessary 

144.1 2. Section 144.1 is amended as follows: 

Adding new paragraph (f)(1)(viii); and b. Revising the first two sentences in paragraph (g) introductory text. * * * * * (f) * * * (1) * * * (viii) Subpart H of this part sets forth requirements for owners or operators of Class VI injection wells. * * * * * (g) Scope of the permit or rule requirement. The UIC Permit Program regulates underground injections by six classes of wells (see definition of ‘‘well injection,’’ § 144.3). The six classes of wells are set forth in § 144.6. All owners or operators of these injection wells must be authorized either by permit or rule by the Director. * * * 

Support revision to include a sixth class of wells. 
GWPC Recommendations Page 2 of 40 2 

Rule Provision EPA Proposal GWPC Recommendations 

144.6 3. Section 144.6 is amended as follows: 

Revising paragraph (e); and b. Adding new paragraph (f). * * * * * (e) Class V. Injection wells not included in 

Class I, II, III, IV, or VI. Specific types of Class V injection wells are described in § 144.81. 

(f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath the lowermost formation containing a USDW. 

(4) For enhanced recovery of oil or natural gas where geologic sequestration is occurring during or in connection with enhanced recovery of oil or natural gas provided (i) there is reasonable expectation of more than insignificant future production volumes or rates as a result of carbon dioxide injection and (ii) operating pressures are no higher than reasonably necessary to produce such volumes or rates; (f) Class VI. Wells injecting a carbon dioxide stream for geologic sequestration except those wells described in subsection (b)(4) of this section or otherwise excluded from this Class. 

There should nconcerning injectiolevels. The determbe based upon aespecially true in lthe definition of greater than 10K several states incmight be prevesequestration as a limited to above Usome USDW’s. Thotherwise good excluded, thus decgeologic sequestraThe GWPC also retaining all geoloreservoirs under programs and creafor geologic storsubclass (Class Iwells that depart frwells for enhanceapplication of Clawould eliminate anII CO2 injection wmight also need a the need to changstate agency to an

144.15 4. Adding § 144.15 to read as follows. 

§ 144.15 Prohibition of non-experimental Class V wells for geologic sequestration. The construction, operation or maintenance of any non-experimental Class V geologic sequestration well is prohibited. 

This provision should be deleted if EPA does limit Class VI wells to injection below the lowermost USDW in the final rule to allow Directors to selectively authorize GS in areas with USDWs below the injection zone. In addition, it is recommended that all GS into basalts, coal seams, salt domes, and shales be conducted under Class V as experimental wells initially and then as commercial scale Class V wells/projects if the experimental projects demonstrate that these sites can be suitable for geological sequestration while preventingendangerment of USDWs. 

Keeping these weEPA and the statedevelop suitable pwells and to tailoagencies are reregulations. 
GWPC Recommendations Page 3 of 40 3 

Rule Provision EPA Proposal GWPC Recommendations 

144.18 5. Adding § 144.18 to read as follows. 

§ 144.18 Requirements for class VI wells.  Owners or operators of Class VI wells must obtain a permit. Class VI wells are not authorized by rule to inject. 

Support the proposed language. Agree with EPA’s r

144.36 6. Section 144.36 is amended by revising 

the first two sentences in paragraph (a) to read as follows: 

§ 144.36 Duration of permits.  (a) Permits for Class I and V wells shall be effective for a fixed term not to exceed 10 years. UIC Permits for Class II, III and VI wells shall be issued for a period up to the operating life of the facility. * * ** * * * * 

Support the proposed language. 

The proposed provlong as the established for Aoof the project incloperational decassurance, etc. It also depend on 14revocation of Class 

 7. Section 144.39 is amended by revising the second sentence in paragraph (a) introductory text and by revising the second sentence in paragraph (a)(3) introductory text to read as follows: 

§ 144.39 Modification or revocation and reissuance of permits. * * * * * 

Support the proposed language. Agree with EPA’s r

144.39 (a) * * * For Class I hazardous 

waste injection wells, Class II, Class III or 

Class VI wells the following may be causes for revocation and reissuance as well as modification; and for all other wells the following may be cause for revocation or reissuance as well as modification when the permittee requests or agrees. * * * 

* * * * *  (3) * * * Permits other than for Class I hazardous waste injection wells, Class II, Class III or Class VI wells may be modified during their terms for this cause only as follows: * * * 

Support the proposed language. Agree with EPA’s r
GWPC Recommendations Page 4 of 40 4 

Rule Provision EPA Proposal GWPC Recommendations 

* * * * * 

144.51 8. Section 144.51 is amended by 

revising the first sentence in paragraph (q)(1) and the first sentence in paragraph (q)(2) to read as follows: 

§ 144.51 Conditions applicable to all permits. * * * * *  (q) * * *  (1) The owner or operator of a Class I, II, III or VI well permitted under this part shall establish mechanical integrity prior to commencing injection or on a schedule determined by the Director. Thereafter the owner or operator of Class I, II, and III wells must maintain mechanical integrity as defined in § 146.8 and the owner or operator of Class VI wells must maintain mechanical integrity as defined in § 146.89 of this chapter. * * * 

 (q) * * *  (1) The owner or operator of a Class I, II, III or VI well permitted under this part shall establish mechanical integrity prior to 

commencing injection or on a schedule determined by the Director. Thereafter the owner or operator of Class I, II, and III wells must maintain mechanical integrity as defined in §146.8 and the owner or operator of Class VI wells must maintain mechanical integrity as defined in §146.89 of this chapter. 

EPA may want to ras this implies thabased on Directo146.89 with respecthe two provisions an initial MIT andiscretion to allow after some injectiorequired during injection zone. 

 (2) When the Director determines that a Class I, II, III or VI well lacks mechanical integrity pursuant to § 146.8 or § 146.89 for Class VI of this chapter, he/she shall give written notice of his/ her determination to the owner or operator. * * * 

* * * * * 

Support the proposed language. Agree with EPA’s r

144.52 9. Section 144.52 is amended by 

revising paragraph (a)(8) to read as follows: 

§ 144.52 Establishing permit conditions.  (a) * * *  (8) Mechanical integrity. A permit 

for any Class I, II, III or VI well or injection project which lacks mechanical integrity shall include, and for any Class V well may include, a condition prohibiting injection operations until the permittee shows to the satisfaction of the Director under § 146.08 or 

Support the proposed language. Agree with EPA’s r
GWPC Recommendations Page 5 of 40 5 

Rule Provision EPA Proposal GWPC Recommendations 

§ 146.89 for Class VI that the well has mechanical integrity. * * * * * 

144.55 § 144.55 Corrective action. 

 (a) Coverage. Applicants for Class 

I, II, (other than existing), III or VI injection well permits shall identify the location of all known wells within the injection well’s area of review which penetrate the injection zone, or in the case of Class II wells operating over the fracture pressure of the injection formation, all known wells within the area of review penetrating formations affected by the increase in pressure. Applicants for Class VI shall perform corrective action as specified in § 146.84.* * * 

* * * * * 

Support the proposed language. Agree with EPA’s r

144.80 11. Section 144.80 is amended by 

revising the first sentence in paragraph (e) and by adding paragraph (f) to read as follows: 

§ 144.80 What is a Class V injection well? * * * * *  (e) Class V. Injection wells not included in Class I, II, III, IV or VI. * * *  (f) Class VI. Wells used for geologic sequestration of carbon dioxide.

 (4) For enhanced recovery of oil or natural gas where geologic sequestration is occurring during or in connection with enhanced recovery of oil or natural gas provided (i) there is reasonable expectation of more than insignificant future production volumes or rates as a result of carbon dioxide injection and (ii) operating pressures are no higher than reasonably necessary to produce such volumes or rates; (f) Class VI. Wells injecting a carbon dioxide stream for geologic sequestration except those wells described in subsection (b)(4) of this section or otherwise excluded from this Class. 

There should nconcerning injectiolevels. The determbe based upon aespecially true in lthe definition of greater than 10K several states incmight be prevesequestration as a limited to above Usome USDW’s. Thotherwise good excluded, thus decgeologic sequestraThe GWPC also retaining all geoloreservoirs under programs and creafor geologic storsubclass (Class Iwells that depart frwells for enhanceapplication of Cla
GWPC Recommendations Page 6 of 40 6 

Rule Provision EPA Proposal GWPC Recommendations 

would eliminate anII CO2 injection wmight also need a the need to changstate agency to an

Part 146 12. The authority citation for part 

146 continues to read as follows: 

Authority: Safe Drinking Water Act 

42, U.S.C. 300f et seq.; Resource Conservation and Recovery Act, 42 U.S.C. 6901 et seq.

Support the proposed language. Agree with EPA’s r

146.5 13. Section 146.5 is amended as 

follows: 

 a. Revising the first sentence in paragraph (e) introductory text; and  b. Adding paragraph (f). (f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath the lowermost formation containing an underground source of drinking water (USDW).

(4) For enhanced recovery of oil or natural gas where geologic sequestration is occurring during or in connection with enhanced recovery of oil or natural gas provided (i) there is reasonable expectation of more than insignificant future production volumes or rates as a result of carbon dioxide injection and (ii) operating pressures are no higher than reasonably necessary to produce such volumes or rates; (f) Class VI. Wells injecting a carbon dioxide stream for geologic sequestration except those wells described in subsection (b)(4) of this section or otherwise excluded from this Class. 

There should nconcerning injectiolevels. The determbe based upon aespecially true in lthe definition of greater than 10K several states incmight be prevesequestration as a limited to above Usome USDW’s. Thotherwise good excluded, thus decgeologic sequestraThe GWPC also retaining all geoloreservoirs under programs and creafor geologic storsubclass (Class Iwells that depart frwells for enhanceapplication of Clawould eliminate anII CO2 injection wmight also need a the need to changstate agency to an
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Part 146 Subpart H 

14. Subpart H is added to read as follows: Subpart H—Criteria and Standards Applicable to Class VI Wells Sec. 146.82 Required Class VI permit information. 146.83 Minimum criteria for siting. 146.84 Area of review and corrective action. 146.85 Financial responsibility. 146.86 Injection well construction requirements. 146.87 Logging, sampling, and testing prior to injection well operation. 

Support the proposed language. Agree with EPA’s r

146.81 Applicability.

 (a) This subpart establishes criteria and standards for underground injection control programs to regulate Class VI carbon dioxide geologic sequestration injection wells. 

Support the proposed EPA language. Agree with EPA’s r

 (b) This subpart applies to wells used to inject carbon dioxide specifically for the purpose of geologic sequestration, i.e., the long-term containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. 

 (b) This subpart applies to wells used to inject carbon dioxide streams into saline formations for the purpose of geologic sequestration, i.e., the long-term containment of a carbon dioxide stream in subsurface geologic formations. 

Use of the term implied Class VI wpurposes and still bRemove “gaseousterms are implied dioxide. See the rationaregarding inclusion 

 (c) This subpart applies to owners and operators of permit or rule-authorized Class I industrial, Class II, or Class V experimental carbon dioxide injection projects who seek to apply for a Class VI geologic sequestration permit for their well or wells. If the Director determines that USDWs will not be endangered, such wells are exempt, at the Director’s discretion, from the casing and cementing requirements at 

 (c) This subpart applies to owners and operators of permit or rule-authorized Class Iindustrial, Class II, or Class V experimental carbon dioxide injection projects who seek to apply for a Class VI geologic sequestration permit for their well or wells or to convert to Class II GS operation. If the Director determines that USDWs will not be endangered, such wells are exempt, at the Director’s discretion, from such Class VI requirements contained in this subpart 

The proposed EPcasing and cemeshould have threquirements as Class VI. 
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§§ 146.86(b) and 146.87(a)(1) through (3). as the Director specifies. 

146.81(d) Definitions 

 (d) Definitions. The following 

definitions apply to this subpart. To the extent that these definitions conflict with those in § 146.3 these definitions govern: 

Area of review means the region 

surrounding the geologic sequestration project that may be impacted by the injection activity. The area of review is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream. 

Area of review means the subsurface threedimensional extent of the carbon dioxide stream plume associated pressure front, and displaced brine, as well as the overlying formations and surface area above that delineated region. 

Suggest removal replacement with : dimensional extenassociated pressuwell as the surfaregion.” Comment on the inbecause the AoR area defined by thInclusion of “surropen-ended and a

Carbon dioxide plume means the underground extent, in three dimensions, of an injected carbon dioxide stream. Carbon dioxide stream means carbon dioxide that has been captured from an emission source (e.g., a power plant), plus incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. This subpart does not apply to any carbon dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261. 

Carbon dioxide stream means carbon dioxide, plus associated substances derived from the source materials and any processing, and any substances added to the stream to enable or improve the injection process. This subpart does not apply to any carbon dioxide stream that meets the definition of a hazardous waste under 40 CFR part 261. 

Insert the definmeans a mathemathe site geometrdifferences betwefluids.” Source of CO2 scontext of defining 

Confining zone means a geologic formation, group of formations, or part of a formation stratigraphically overlying the injection zone that acts as a barrier to fluid movement.

Confining zone means a geological formation, group of formations, or part of a formation that is capable of limiting fluid movement from an injection zone.

The current UIC zone is preferable are no special circwarrant a change 

Corrective action means the use of Director approved methods to assure that wells within the area of review do not serve as conduits for the movement of fluids into underground sources of drinking water 

Support the proposed EPA language. Agree with EPA’s r
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(USDW).

“Fault means a surface or zone of rock fracture along which there has [or has not] been displacement.” 

Add definition of provisions. This insertion of the displacement to where there has be

Geologic sequestration means the long-term containment of a gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic formations. This term does not apply to its capture or transport.

Geologic sequestration means the long-term containment of a carbon dioxide stream in subsurface geologic formations. This term does not apply to its capture or transport. 

Suggest removing as these terms arcarbon dioxide. 

Geologic sequestration project means an injection well or wells used to emplace a carbon dioxide stream beneath the lowermost formation containing a USDW. It includes the subsurface three-dimensional extent of the carbon dioxide plume, associated pressure front, and displaced brine, as well as the surface area above that delineated region.

Geologic sequestration project means an injection well or wells used to emplace a carbon dioxide stream into an injection zone for geologic sequestration. 

Replace “beneatcontaining a USDW Suggest moving definition of AOR. 

No EPA definition Geologic sequestration site means The GWPC believ

needed as the term the rule. 

Injection zone means a geologic formation, group of formations, or part of a formation that is of sufficient a real extent, thickness, porosity, and permeability to receive carbon dioxide through a well or wells associated with a geologic sequestration project. 

Injection zone means a geological ‘‘formation’’, group of formations, or part of a formation receiving fluids through a well. 

Existing definition not need to be sufficiency is not a dealt with elsewhe

Post-injection site care means appropriate monitoring and other actions (including corrective action) needed following cessation of injection to assure that USDWs are not endangered as required under § 146.93.

Post-injection site care means monitoring and other actions (including corrective action) following cessation of injection, as required under 146.93. 

The definition shoimpose substanrequirements are sections. 
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Pressure front means the zone of elevated pressure that is created by the injection of carbon dioxide into the subsurface. For the purposes of this subpart, the pressure front of a carbon dioxide plume refers to a zone where there is a pressure differential sufficient to cause the movement of injected fluids or formation fluids into a USDW. 

Pressure front means the zone of elevated pressure that is created by the injection of the carbon dioxide stream into the subsurface, where there is a pressure differential sufficient to cause movement of the carbon dioxide stream or formation fluids from the injection zone into a USDW. 

Proposal removes provide clarity and Insert “from the inje

Site closure the point/time, as determined by the Director following the requirements under § 146.93, at which the owner or operator of a GS site is released from postinjection site care responsibilities.

Site closure means the point/time, as determined by the Director following the requirements under §146.93, at which the owner or operator of a GS project is released from post-injection site care responsibilities. 

Add “means” Suggest using “Gother definitions 

Transmissive fault or fracture means a fault or fracture that has sufficient permeability and vertical extent to allow fluids to move between formations. 

Transmissive fault or fracture means a fault or fracture that has sufficient permeability and vertical extent to allow fluids to move beyond the confining zone. 

Recommends cha“beyond the confiformations is insumultiple zones with

146.82 Required Class VI permit information 

This section sets forth the information which the owner or operator must submit to the Director in order to be permitted as a Class VI well. The application for a permit for construction and operation of a Class VI well must include the following: 

Support the proposed EPA language. Agree with EPA’s r

146.82(a) (a) Information required in 40 CFR 

144.31(e)(1) through (6); 

Support the proposed EPA language. Agree with EPA’s r

 (b) A map showing the injection well(s) for which a permit is sought and the applicable area of review. Within the area of review, the map must show the number, or name and location of all injection wells, producing wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, State or EPA approved subsurface cleanup sites, surface bodies of water, springs, mines (surface and subsurface), quarries, water wells and other pertinent surface features including structures intended for human 

occupancy and roads. The map should also show faults, if known or suspected. Only information of public record is required to be 

 (b) A surface map showing the proposed locations for the injection well(s) for which a permit is sought and the applicable area of review. Within the area of review, the map must show the number, or name and location of all known injection wells, producing wells, abandoned wells, plugged wells or dry holes, deep stratigraphic boreholes, State or EPA approved subsurface cleanup sites, surface bodies of water, springs, mines (surface and subsurface), quarries, water wells and other pertinent surface features including structures intended for human occupancy and roads. Only information of public record is required to be 

Insert “known” befoSuggests removing shown on maps expression of the (d) below and this 
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included on this map; included on this map; 

 (c) The area of review based on modeling, using data obtained during logging and testing of the well and the formation as required by paragraphs (l), (r), and (s) of this section; 

 (c) A map delineating the area of review based upon modeling, using all available data including data available from any logging and testing of wells within the area of review. 

Is this supposed tcross section or seappears to be relaalready drilled. Thinformation to rece

(d) Information on the geologic structure and hydrogeologic properties of the proposed storage site and overlying formations, including: 

(1) Maps and cross sections of the area of review; (2) Location, orientation, and properties of known or suspected faults and fractures that may transect the confining zone(s) in the area of review and a determination that they would not interfere with containment; 

(d) Sufficient information on the geologic structure and reservoir properties of the proposed storage site and overlying formations, including: (1) Isopach maps of the proposed injection and confining zone(s), a structural contour map aligned with the top of the proposed injection zone, and at least two geologic cross sections of the area of review reasonably perpendicular to each other showing the geologic formations from the surface to total depth. (2) Location, orientation, and properties of known or suspected subsurface faults that may transect the confining zone(s) in the area of review and a determination that they would not interfere with containment; 

Fractures can be impossible to find GWPC also reco“Sufficient” before this is more precise

 (3) Information on seismic history including the presence and depth of seismic sources and a determination that the seismicity would not interfere with containment; 

 (4) Data on the depth, areal extent, thickness, mineralogy, porosity, permeability and capillary pressure of the injection and confining zone(s); including geology/facies changes based on field data which may include geologic cores, outcrop data, seismic surveys, well logs, and names and lithologic descriptions;  (5) Geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid pressures within the confining zone; and 

 (3) Information on seismic history that have affected the proposed area of review including knowledge of previous seismic events and history of these events, including the presence and depth of seismic sources and a determination that the seismicity would not compromise containment;  (4) Data sufficient to demonstrate the effectiveness of the injection and confining zone(s), including data on the depth, areal extent, thickness, mineralogy, porosity, vertical permeability reservoir pressure and of the injection and confining zone(s) within the area of review; including geologic changes based on field data which may include geologic cores, outcrop data, seismic surveys, well logs, capillary pressure tests and names and lithologic descriptions;  (5) Geomechanical information on the 

Capillary pressure the lab; how comgoes into the grosufficient to do thwhole of the cRewording keeps pressure in the mandatory use. 
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confining zone(s) within the area of review; and 

 (6) Geologic and topographic maps and cross sections illustrating regional geology, hydrogeology, and the geologic structure of the local area. 

Support the EPA language. 

146.82(e) (e) A tabulation of all wells within the 

area of review which penetrate the injection or confining zone(s). Such data must include a description of each well’s type, construction, date drilled, location, depth, record of plugging and/ or completion, and any additional information the Director may require; 

 (e) A compilation of all artificial penetrations within the area of review which penetrate the injection or confining zone(s). Such data must include a description of each well’s type, construction, date drilled, location, depth, record of plugging and/ or completion, and any additional information the Director may require; 

The GWPC felt thaappropriate than ttabulation implies can take numerous 

 (f) Maps and stratigraphic cross sections indicating the general vertical and lateral limits of all USDWs, water wells and springs within the area of review, their positions relative to the injection zone(s) and the direction of water movement, where known; 

(f) Maps and stratigraphic cross sections indicating the general vertical and lateral limits of all USDWs, the location of water wells and perennial springs within the area of review, their positions relative to the injection zone(s) and the direction of water movement, where known; 

Clarification: Use springs will prevenintermittent springsignificant. 

(g) Baseline geochemical data on subsurface formations, including all USDWs in the area of review; 

 (g) Compilation of available baseline geochemical data on the proposed injection zone and nearest adjacent porous and permeable formation to the confining zone, existing utilized water supply aquifers and any other USDWs designated by the Director. 

It will be unduly USDWs” in some more appropriate designated by the 

 (h) Proposed operating data: 

 (1) Average and maximum daily rate and volume of the carbon dioxide stream;  (2) Average and maximum injection pressure;  (3) The source of the carbon dioxide stream; and  (4) An analysis of the chemical and physical characteristics of the carbon dioxide stream; 

 (h) Proposed operating data:  (1) Average and maximum daily injection rate and volume of the carbon dioxide stream;  (2) Average and maximum surface injection pressure;  (3) The source of the carbon dioxide stream; and  (4) An analysis of the chemical and physical characteristics of the carbon dioxide stream; 

Clarification: Addwill make it clear ais to measured. 
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146.82(i) (i) The compatibility of the carbon 

dioxide stream with fluids in the injection zone and minerals in both the injection and the confining zone(s), based on the results of the formation testing program, and with the materials used to construct the well; 

 (j) Proposed formation testing program to obtain an analysis of the chemical and physical characteristics of the injection zone and confining zone; 

Support the proposed EPA language. Agree with EPA’s r

 (k) Proposed stimulation program and a determination that stimulation will not interfere with containment; 

 (l) The results of the formation testing program as required in paragraph (j) of this section;  (m) Proposed procedure to outlinesteps necessary to conduct injection operation;  (n) Schematic or other appropriate drawings of the surface and subsurface construction details of the well;  (o) Injection well construction procedures that meet the requirements of § 146.86; 

 (k) Proposed stimulation program and a determination that stimulation will not compromise containment;  (l) The results of the formation testing program as required in paragraph (j) of this section;  (m) Proposed procedure to outline steps necessary to conduct injection operation;  (n) A wellbore schematic of the subsurface construction details and surface wellhead construction.  (o) Injection well construction procedures that meet the requirements of § 146.86; 

“Interfere” is too amby “compromise” wwhere containmen

 (p) Proposed area of review and corrective action plan that meets the requirements under § 146.84; 

 (q) The status of corrective action on wells in the area of review;  (r) All available logging and testing program data on the well required by § 146.87;  (s) A demonstration of mechanical integrity pursuant to § 146.89;  (t) A demonstration, satisfactory to the Director, that the applicant has met the financial responsibility requirements under § 

 (p) Proposed corrective action plan for artificial penetrations within the area of review, if necessary  (q) All available logging and testing program data on the well required by § 146.87;  (r) The proposed demonstration method for mechanical integrity pursuant to  (s) A demonstration, satisfactory to the Director, that the applicant has met the financial responsibility requirements under § 146.85; 

(q) Should be deleapplication procesactivity. This wousubsections after t
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146.85; 

146.82(u) (u) Proposed testing and monitoring 

plan required by § 146.90; 

 (v) Proposed injection well plugging plan required by § 146.92(b);  (w) Proposed post-injection site care and site closure plan required by § 146.93(a);  (x) Proposed emergency and remedial response plan required by § 146.94; and  (y) Any other information requested by the Director. 

 (t) Proposed testing and monitoring plan required by § 146.90;  (u) Proposed injection and monitoring well(s) plugging plan required by § 146.92(b);  (v) Proposed post-injection site care and site closure plan required by § 146.93(a);  (w) Proposed emergency and remedial response plan required by § 146.94; and  (x) Any other information requested by the Director. 

Need to address tif any, included in t

146.83 Minimum criteria for siting 

 (a) Owners or operators of Class VI wells must demonstrate to the satisfaction of the Director that the wells will be sited in areas with a suitable geologic system. The geologic system must be comprised of:  (1) An injection zone of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated volume of the carbon dioxide stream; 

Support the proposed EPA language. Agree with EPA’s r

 (2) A confining zone(s) that is free of transmissive faults or fractures and of sufficient areal extent and integrity to containthe injected carbon dioxide stream and displaced formation fluids and allow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zone(s); and 

 (2) A confining zone(s) that is laterally continuous and free of known transecting, transmissive faults or fractures over an area sufficient to prevent the movement of fluids into a USDW; 

Suggest using thparagraph (2) in reactivation of existhe terms faults or be added. 

 (b) At the Director’s discretion, owners or operators of Class VI wells must 

Delete paragraph This paragraph 

additional zones 
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identify and characterize additional zones that will impede vertical fluid movement, are free of faults and fractures that may interfere with containment, allow for pressure dissipation, and provide additional opportunities for monitoring, mitigation and remediation. 

redundant from pre

146.84 146.84. Area of review and corrective action

 (a) The area of review is the region surrounding the geologic sequestration project that may be impacted by the injection activity. The area of review is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream. 

 (a) The area of review is based on computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream. 

This is the same athat was revised bsentence. Comments on maproposed changes 

 (b) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan to delineate the area of review for a proposed geologic sequestration project, periodically reevaluate the delineation, and perform corrective action that meets the requirements of this section and is acceptable to the Director. As a part of the permit application for approval by the Director, the owner or operator must submit an area of review and corrective action plan that includes the following information: 

 (1) The method for delineating the area of review that meets the requirements of paragraph (c) of this section, including the model to be used, assumptions that will be made, and the site characterization data on which the model will be based; 

 (b) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan to delineate the area of review for a proposed geologic sequestration project, reevaluate the delineation, and perform corrective action that meets the requirements of this section in a manner and at a frequency acceptable to the Director. As a part of the permit application, the owner or operator must submit an area of review and corrective action plan that includes the following information: 

Suggest deletion orecommendation 7RecommendationManagement of GUnder the UIC Pro

Replace with “in a Delete “for approvapproval is implicit 

146.84(b)(2) (2) A description of: 

 (i) The minimum fixed frequency, not to exceed 10 years, the owner or operator proposes to reevaluate the area of review;  (ii) The monitoring and operational conditions that would warrant a reevaluation 

Delete (i) and (ii) Suggest deletion o

and at a frequency 

Suggest deletion comment on (i) 
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of the area of review prior to the next scheduled reevaluation as determined by the minimum fixed frequency established in paragraph (b)(2)(i) of this section.  (iii) How monitoring and operational data (e.g., injection rate and pressure) will be used to inform an area of review reevaluation; and 

 (iv) How corrective action will be conducted to meet the requirements of paragraph (d) of this section, including what corrective action will be performed prior to injection and what, if any, portions of the area of review will have corrective action addressed on a phased basis and how the phasing will be determined; how corrective action will be adjusted if there are changes in the area of review; and how site access will be guaranteed for future corrective action. 

 (iv) How corrective action will be conducted to meet the requirements of paragraph (d) of this section, including what corrective action will be performed prior to injection and what, if any, portions of the area of review will have corrective action addressed on a phased basis and how the phasing will be determined; how corrective action will be adjusted if there are changes in the area of review; and how site access will be assured for future corrective action. 

Replace “guarantecannot be absoluadvance that mboundaries of thassurance of acconerous than guastandard such as “

146.84(c) (c) Owners or operators of Class VI 

wells must perform the following actions to delineate the area of review, identify all wells that require corrective action, and perform corrective action on those wells: 

 (1) Predict, using computational modeling, the projected lateral and vertical migration of the carbon dioxide plume and formation fluids in the subsurface from the commencement of injection activities until the plume movement ceases, pressure differentials sufficient to cause the movement of injected fluids or formation fluids into a USDW are no longer present, or after a fixed time period as determined by the Director. The model must: 

 (c) Owners or operators of Class VI wells must perform the following actions to delineate the area of review, identify all wells that require corrective action, and perform corrective action on those wells:  (1) Predict, using computational modeling, the projected lateral and vertical migration of the carbon dioxide plume and formation fluids in the subsurface from the commencement of injection activities until the plume movement ceases, pressure differentials sufficient to cause the movement of injected fluids or formation fluids into a USDW are no longer present, or for a fixed time period as determined by the Director. The model must: 

Should say “for” no

146.84(c)(i) (i) Be based on detailed geologic 

data collected to characterize the injection zone, confining zone and any additional zones; and anticipated operating data, including injection pressures, rates and total volumes over the proposed life of the 

 (i) Be based on detailed geologic data collected to characterize the injection zone,confining zone; and anticipated operating data, including injection pressures, rates and total volumes over the duration of injection;  (ii) Take into account relevant geologic 

Suggest deletion onot need to includthe current CFR dincludes multiple zShould be geologwith other p
GWPC Recommendations Page 17 of 40 17 

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geological sequestration project;  (ii) Take into account any geologic heterogeneities, data quality, and their possible impact on model predictions; and  (iii) Consider potential migration through faults, fractures, and artificial penetrations. 

heterogeneities, and data quality, and their possible impact on model predictions; and  (iii) Consider potential migration through faults, fractures, and artificial penetrations. 

sequestration projeSuggest “duration geological sequest Suggest “relevant” Insert “and” betwee

 (2) Using methods approved by the Director, identify all penetrations, including active and abandoned wells and underground mines, in the area of review that may penetrate the confining zone. Provide a description of each well’s type, construction, date drilled, location, depth, record of plugging and/or completion, and any additional information the Director may require; and 

 (2) Using methods approved by the Director, identify all known artificial penetrations into the confining zone, including active and abandoned wells and underground mines, in the area of review that may penetrate the confining zone. Provide a description of each well’s type, construction, date drilled, location, depth, record of plugging and/or completion, and any additional information the Director may require; and 

Insert “known aconfining zone” 

 (3) Determine which abandoned wells in the area of review have been plugged (as required by § 146.92) in a manner that prevents the movement of carbon dioxide or associated fluids that may endanger USDWs 

 (3) Determine which abandoned wells identified in 146.84 (c) (2) have been plugged (as required by §146.92) in a manner that prevents the movement of carbon dioxide or displaced formation fluids that may endanger USDWs. 

Add identified in 14Remove “area of reSuggest change formation fluids.” Aif EPA means regulation should jneed to define ass

146.84(d) (d) Owners or operators of Class VI 

wells must perform corrective action on all wells in the area of review that are determined to need corrective action using methods necessary to prevent the movement of fluid into or between USDWs including use of corrosion resistant materials, where appropriate. 

 (d) Owners or operators of Class VI wells must perform corrective action using materials suitable for use with carbon dioxide streams, on all wells identified in 146.84(c)(2) that are determined to need corrective action”. 

Re-write as followVI wells must pcorrosion resistant all wells identifidetermined to need 

 (e) If monitoring data indicate an endangerment to USDWs, the owner or operator must notify the Director and cease operations as required by § 146.94. 

Delete Why is this neede

notification and ces
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 (f) At the minimum fixed frequency, not to exceed 10 years, as specified in the area of review and corrective action plan, or when monitoring and operational conditions warrant, owners or operators must: 

 (1) Reevaluate the area of review in the same manner specified in paragraph (c)(1) of this section;  (2) Identify all wells in the reevaluated area of review that require corrective action in the same manner specified in paragraph (c)(2) of this section; 

 (f) As specified in the approved area of review and corrective action plan, or when monitoring and operational conditions warrant, owners or operators must  (1) Reevaluate the area of review in the same manner specified in paragraph (c)(1) of this section;  (2) Identify all wells in the reevaluated area of review that require corrective action in the same manner specified in paragraph (c)(2) of this section; 

Delete “At the mexceed 10 years”. Insert “approved” b

 (3) Perform corrective action on wells requiring corrective action in the reevaluated area of review in the same manner specified in paragraph (c)(3) of this section; and 

 (4) Submit an amended area of review and corrective action plan or demonstrate to the Director through monitoring data and modeling results that no amendment to the area of review and corrective action plan is needed. 

 (3) Perform corrective action on wells requiring corrective action in the reevaluated area of review in the same manner specified in paragraph (c)(3) of this section; and  (4) Submit an amended area of review and corrective action plan or demonstrate to the Director through monitoring data and modeling results that no change to the area of review and corrective action plan is needed. 

Suggest “change” because the term to mean an official 

146.84(g) (g) The emergency and remedial 

response plan (as required by § 146.94) and a demonstration of financial responsibility (as described by § 146.85) must account for 

the entire area of review, regardless of whether or not corrective action in the area of review is phased. 

 (g) The emergency and remedial response plan (as required by § 146.94) and a demonstration of financial responsibility (as described by § 146.85) must account for the entire area of review [as modified], regardless of whether or not corrective action in the area of review is phased. 

Need to add phrreevaluations and occurring. Additaddresses this con

146.85 146.85 Financial responsibility 

 (a) The owner or operator must demonstrate and maintain financial responsibility and resources for corrective action (that meets the requirements of § 146.84), injection well plugging (that meets the requirements of § 146.92), post-injection site care and site closure (that meets the requirements of § 146.93), and emergency and remedial response (that meets the requirements of

No specific language recommended. See rationale 

Maintenance of prelease by the Direthe well has beeoperator be alloweDirector for the presponsibility elem
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§ 146.94) in a manner prescribed by the Director until:  (1) The Director receives and approves the completed post-injection site care and site closure plan; and  (2) The Director determines that the site has reached the end of the postinjection site care period. 

 (b) The owner or operator must provide to the Director, at a frequency determined by the Director, written updates of adjustments to the cost estimate to account for any amendments to the area of review and corrective action plan (§ 146.84), the injection well plugging plan (§ 146.92), and the post-injection site care and site closure plan (§ 146.93). 

 (b) The owner or operator must provide to the Director, at a frequency determined by the Director, but no more frequently than annually, 

written updates or adjustments to the cost estimate to account for any changes to: the area of review and corrective action plan (§146.84), the injection well plugging plan (§146.92), and the post-injection site care and site closure plan (§146.93). 

Does this contempadjustments? Suggest “change” Clarification on wadjustments” wouincluded, at what fr

146.85(c) (c) The owner or operator must 

notify the Director of adverse financial conditions such as bankruptcy that may affect the ability to carry out injection well 

plugging and post-injection site care and site closure. 

 (c) The owner or operator must notify the Director of adverse financial conditions that may affect the ability to carry out injection well plugging and post-injection site care and site closure. 

Delete “such as examples of unnecessary. 

 (d) The operator must provide an adjustment of the cost estimate to the Director if the Director has reason to believe that the original demonstration is no longer adequate to cover the cost of injection well plugging (as required by § 146.92) and postinjection site care and site closure (as required by § 146.93). 

 (d) The operator must provide an adjustment of the cost estimate to the Director if the Director has reason to believe that the most recent demonstration is no longer adequate to cover the cost of injection well plugging (as required by § 146.92) and post-injection site care and site closure (as required by § 146.93). 

The reference shonot the original demThis is a one timupdates are covereRecognize that the

146.86 6. Injection well construction requirements 

 (a) General. The owner or operator must ensure that all Class VI wells are constructed and completed to:  (1) Prevent the movement of fluids into or between USDWs or into any unauthorized zones;  (2) Permit the use of appropriate 

 (a) General. The owner or operator must ensure that all Class VI wells are constructed and completed to:  (1) Prevent the movement of fluid containing any contaminant into USDWs per 40 CFR Part 144.12(a).  (2) Permit the use of appropriate testing devices and workover tools; and  (3) Permit continuous monitoring of the 

Mirror language coin (1). The GWPC suggeand make it consifluid movement. 
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testing devices and workover tools; and  (3) Permit continuous monitoring of the annulus space between the injection tubing and long string casing. 

annulus space between the injection tubing and long string casing. 

 (b) Casing and Cementing of Class VI Wells. 

 (1) Casing and cement or other materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the life of the geologic sequestration project. All well materials must be compatible with fluids with which the materials may be expected to come into contact and meet or exceed standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards acceptable to the Director. The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information: 

 (1) Casing and cement or other materials used in the construction of each Class VI well must have sufficient structural strength and be designed for the life of the operating life of the well. All well materials must be compatible with fluids with which the materials may be expected to come into contact and meet or exceed test standards or practices developed for such materials by the American Petroleum Institute, 

ASTM International, or comparable standards 

acceptable to the Director. The casing and cementing program must be designed to prevent the movement of fluids into or between USDWs. In order to allow the Director to determine and specify casing and cementing requirements, the owner or operator must provide the following information: 

Suggest substitutin“the life of the geoThe GWPC determproject was a necalculated and thdesigning a casing IMirror the non end

146.86(b)(1) (i) Depth to the injection zone; 

 (ii) Injection pressure, external pressure, internal pressure and axial loading;  (iii) Hole size;  (iv) Size and grade of all casing strings (wall thickness, external diameter, nominal weight, length, joint specification and construction material);  (v) Corrosiveness of the carbon dioxide stream, and formation fluids;  (vi) Down-hole temperatures;  (vii) Lithology of injection and 

 (i) Depth to the injection zone;  (iii) Hole size;  (iv) Size and grade of all casing strings (wall thickness, external diameter, nominal weight, length, joint specification and construction material);  (v) Predicted corrosiveness of thcombined carbon dioxide stream and formation fluids; 

e 

 (vi) Down-hole temperatures and pressures;  (vii) Lithology of injection and confining zones; 

What is meant by Recommend deletInsert “and pressurCannot measure stream because it yield pH measurem
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confining zones; 

 (viii) Type or grade of cement; and 

 (ix) Quantity, chemical composition, and temperature of the carbon dioxide stream. 

 (viii) Type or grade of cement and additives; and  (ix) Quantity, chemical composition, and temperature of the carbon dioxide stream. 

Insert “and additive

 (2) Surface casing must extend through the base of the lowermost USDW and be cemented to the surface. 

 (2) Surface casing must extend through the base of the lowermost USDW above the injection zone and be cemented to the surface. 

Insert “above the “USDW.” In some deep and this stsequestration in thallowing the Direapprove alternative cement around the 

 (3) At least one long string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages. 

 (3) At least one long string casing, using a sufficient number of centralizers, which at a minimum, would create a cement bond through the confining zone, and which must extend to the injection zone and must be isolated by placing cement and/or other isolation technologies as necessary to provide adequate isolation of the injection zone and provide for protection of USDWs. 

Cementing to surfUSDWS, and may follows. Cement ability to monitor would limit flexibilitthe proposal wodevelopment of alRP90 for descripmanaging situatiopressure. Industunder the class effectiveness of ex

146.86(b) (4) Circulation of cement may be 

accomplished by staging. The Director may approve an alternative method of cementing in cases where the cement cannot be recirculated to the surface, provided the owner or operator can demonstrate by using logs that the cement does not allow fluid movement behind the well bore. 

Delete Same as above 

 (5) Cement and cement additives must be compatible with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the design life of the geologic sequestration project. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to 

 (5) Cement and cement additives must be suitable for use with the carbon dioxide stream and formation fluids and of sufficient quality and quantity to maintain integrity over the operating life the well. The integrity and location of the cement shall be verified using technology capable of evaluating cement quality radially and identifying the location of channels to ensure that USDWs are not endangered. 

Experience with program demonstrcementing materiacements have beeoperations withoReference API COBill Carey (SACRplacement and antype). 
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ensure that USDWs are not endangered. Once the well is p

other portions of th

146.86(c) (c) Tubing and packer. 

 (1) All owner and operators of Class VI wells must inject fluids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the Director.  (2) In order for the Director to determine and specify requirements for tubing and packer, the owner or operator must submit the following information:  (i) Depth of setting;  (ii) Characteristics of the carbon dioxide stream (chemical content, corrosiveness, temperature, and density); 

 (c) Tubing and packer.  (1) All owner and operators of Class VI wells must inject fluids through tubing with a packer set at a depth opposite a cemented interval at the location approved by the Director.  (2) In order for the Director to determine and specify requirements for tubing and packer, the owner or operator must submit the following information:  (i) Depth of setting;  (ii) Composition of the carbon dioxide stream; 

What does corrmeasured? Cannot measure dioxide stream. Composition of the a tubing and paccharacteristics are 

146.86(c)(2) (iii) Injection pressure; 

 (iv) Annular pressure;  (v) Injection rate (intermittent or continuous) and volume of the carbon dioxide stream;  (vi) Size of casing; and  (vii) Tubing tensile, burst, and collapse strengths. 

 (iii) Maximum proposed Injection temperature and pressure;  (iv) Maximum proposed Annular pressure;  (v) Maximum proposed Injection rate (intermittent or continuous) and volume of the carbon dioxide stream; 

It is more helpfinformation. The GWPC also r“proposed in (iii), (to an application permit conditions 

146.87 7. Logging, sampling, and testing prior to 

injection well operation 

 (a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formations to assure conformance with the injection well construction requirements under § 146.86, 

 (a) During the drilling and construction of a Class VI injection well, the owner or operator must run appropriate logs, surveys and tests to determine or verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, all relevant geologic formations to assure conformance with the injection well construction requirements under §146.86, and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a 

In well defined frequently unnecesdiscretion to selenecessary to ensinformation are avwhere a number logging of surface information. In particular, this creduce the requirinstalled for a proje
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and to establish accurate baseline data against which future measurements may be compared. The owner or operator must submit to the Director a descriptive report prepared by a knowledgeable log analyst that includes an interpretation of the results of such logs and tests. At a minimum, such logs and tests must include: 

knowledgeable log analyst that includes an interpretation of the results of such logs and tests. The Director may require such logs and tests as may be needed after taking into account the availability of similar data in the area of the drilling site, the construction plan, and the need for additional information that may arise from time to time as the construction of the well progresses and these may include the following: 

 (1) Deviation checks during drilling on all holes constructed by drilling a pilot hole which are enlarged by reaming or another method. Such checks must be at sufficiently frequent intervals to determine the location of the borehole and to assure that vertical avenues for fluid movement in the form of diverging holes are not created during drilling; and 

Support the proposed EPA language. Agree with EPA’s r

146.87(a) (2) Before and upon installation of 

the surface casing: 

Support the proposed EPA language. Agree with EPA’s r

 (i) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and 

(i) Resistivity, spontaneous potential, and caliper logs before the casing is installed; and 

After a few wells 

evaluations are frlittle new informatioappropriate to makmandatory require146.87(a) would gdiscretion. 

 (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented. 

(ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented. 

Unusual to run theuniformity of shallowhy it is approprirather than mandarevision to 146.87necessary discretio

 (3) Before and upon installation of the long string casing: 

Support the proposed EPA language. Agree with EPA’s r

 (i) Resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder logs, and any other logs the Director requires for the given geology before the casing is installed; and 

Support the proposed EPA language. 
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 (ii) A cement bond and variable density log, and a temperature log after the casing is set and cemented. 

 (ii) Cement evaluation logs after the casing is set and cemented to evaluate cement quality with sufficient radial resolution to identify channels or missing cement. 

Acceptable to spe

however, special loother information fProvides more flelog to demonstrate 

146.87(a)(4) (4) A series of tests designed to 

demonstrate the internal and external mechanical integrity of injection wells, which may include: 

 (i) A pressure test with liquid or gas; (ii) A tracer survey such as oxygenactivation logging;  (iii) A temperature or noise log;  (iv) A casing inspection log, if required by the Director; and  (5) Any alternative methods that provide equivalent or better information and that are required of and/or approved of by the Director. 

 (4) Test(s) designed to demonstrate the internal and external mechanical integrity of injection wells, which may include:  (i) A pressure test with liquid or gas;  (ii) Diagnostic tools such as oxygenactivation logging;  (iii) A temperature or noise log; and  (iv) A casing inspection log.  (5) Accept the EPA language and 

numbering. 

Technical and gramIn (iv), “if required We interpret that (5

146.87(b) (b) The owner or operator must take 

and submit to the Director whole cores or sidewall cores of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept cores from nearby wells if the owner or operator can demonstrate that core retrieval is not possible and that such cores are representative of conditions at the well. The Director may require the owner or operator to core other formations in the borehole. 

 (b) The owner or operator must submit to the Director a report describing whole cores or sidewall cores representative of the injection zone and confining system and formation fluid samples from the injection zone(s). The Director may accept data from cores and fluid samples from nearby wells if the owner or operator can demonstrate that such data are representative of conditions in the wellbore. 

The information rproperly describe t

 (c) The owner or operator must record the fluid temperature, pH, conductivity, reservoir pressure and the static fluid level of the injection zone(s). 

 (c) Prior to injection well operation, the owner or operator must record the formation temperature, formation fluid pH and conductivity, and reservoir pressure of the injection zone(s). 

Technical correctstatic fluid level are 
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 (d) At a minimum, the owner or operator must determine or calculate the following information concerning the injection and confining zone(s): 

 (1) Fracture pressure;  (2) Other physical and chemical characteristics of the injection and confining zones; and  (3) Physical and chemical characteristics of the formation fluids in the injection zone. 

Delete all With the exception 

the requirements to other requiRecommend movinow renumbered a

(2) and (3) are also 

 (e) Upon completion, but prior to operation, the owner or operator must conduct the following tests to verify hydrogeologic characteristics of the injection zone: 

 (1) A pump test; or  (2) Injectivity tests. 

 (d) At any time prior to injection well operation, the owner or operator must determine fracture pressures of the injection and confining zones and conduct tests to verify hydrogeologic and geomechanical characteristics of the injection zone, e.g., injectivity tests. 

Allows the use of conducted during tDelete (1) It was felt that Geleast as important The results of a pwell) has no relevaIf current (d) is delbecome (d)

146.87(f) (f) The owner or operator must 

provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director 30 days prior to conducting the first test and submit any changes to the schedule 30 days prior to the next scheduled test. 

 (e) The owner or operator must provide the Director with the opportunity to witness all logging and testing by this subpart. The owner or operator must submit a schedule of such activities to the Director upon spudding the well and submit any changes to the schedule 48 hours prior to the scheduled test. 

The changes refschedules and aClass II requiremeIf current (d) is delbecome (e) 

146.88 8. Injection well operating requirements 

 (a) Except during stimulation, the owner or operator must ensure that injection pressure does not exceed 90 percent of the fracture pressure of the injection zone so as to assure that the injection does not initiate new fractures or propagate existing fractures in the injection zone. In no case may injection pressure initiate fractures in the confining zone(s) or cause the movement of injection or formation fluids that endangers a 

(a) The owner or operator must comply with a maximum injection pressure limit approved by the Director and specified in the permit. In approving a maximum injection pressure limit, the Director shall consider the results of well tests and, where appropriate, geomechanical or other studies that assess the risks of tensile failure and shear failure. The Director shall approve limits that, with a reasonable degree of certainty, will avoid initiation or propagation of fractures in the confining zone or cause otherwise non-transmissive faults transecting 

Maintaining the intcritical parametermaximum pressupercentage of injecnot address the isan appropriate way
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USDW. the confining zone to become transmissive. In 

no case may injection pressure cause movement of injection or formation fluids in a manner prohibited by 40 CFR Part 144.12(a). 

 (b) Injection between the outer-most casing protecting USDWs and the well bore is prohibited. 

 (b) Injection of the CO2 stream between the outermost casing protecting USDWs and the well bore is prohibited. 

Routine injection interval(s) should of this requiremenis being addresseinjection may also be useful. Sometimes inject o

 (c) The owner or operator must fill the annulus between the tubing and the long string casing with a non-corrosive fluid approved by the Director. The owner or operator must maintain on the annulus a pressure that exceeds the operating injection pressure, unless the Director determines that such requirement might harm the integrity of the well. 

 (c) The owner or operator must fill the annulus between the tubing and the long string casing with a corrosion inhibiting fluid approved by the Director. The owner or operator must maintain a positive pressure on the annulus. 

Agency and Indu

UIC program doeThe standard propneither the risk specifications needfor leakage. 

146.88(d) (d) Other than during periods of well 

workover (maintenance) approved by the Director in which the sealed tubing-casing annulus is of necessity disassembled for maintenance or corrective procedures, the owner or operator must maintain mechanical integrity of the injection well at all times. 

Support the proposed EPA language. Agree with EPA’s r
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146.88 (e) The owner or operator must 

install and use continuous recording devices to monitor: The injection pressure; the rate, volume, and temperature of the carbon dioxide stream; and the pressure on the annulus between the tubing and the long string casing and annulus fluid volume; and must install and use alarms and automatic down-hole shut-off systems, designed to alert the operator and shut-in the well when operating parameters such as annulus pressure, injection rate or other parameters approved by the Director diverge beyond permitted ranges and/or gradients specified in the permit; 

 (e) The owner or operator must install and use continuous recording devices to monitor: the injection pressure; the rate, volume, and temperature of the carbon dioxide stream. The owner or operator must regularly monitor the pressure on the annulus between the tubing and the long string casing. The owner or operator must install, test and use alarms and automatic shut-off systems, designed to alert the operator and shut-in the well when operating parameters such as injection rate, injection pressure, or other parameters approved by the Director diverge beyond ranges and/or gradients specified in the permit; 

Over-pressure prensuring compatibdesign strength (compression) sysmay be approprsituations of uniqoffshore or near amandated for all in

146.88 (f) If a down-hole automatic 

shutdown is triggered or a loss of mechanical integrity is discovered, the owner or operator must immediately investigate and identify as expeditiously as possible the cause of the shutoff. If, upon such investigation, the well appears to be lacking mechanical integrity, or if monitoring required under paragraph (e) of this section otherwise indicates that the well may be lacking mechanical integrity, the owner or operator must: 

 (f) If an automatic shutdown is triggered or a loss of mechanical integrity is discovered, the owner or operator must immediately investigate and identify as expeditiously as possible the cause. If, upon such investigation, the well appears to be lacking mechanical integrity, or if monitoring required under paragraph (e) of this section otherwise indicates that the well may be lacking mechanical integrity, the owner or operator must: 

Eliminates requirdevice. Although valves may be nerequired use woureasons such as downhole installatthe valves is diffisurface valves woprovide for visual shut down the inexceeded, the use as effective as dow

146.88(f) (1) Immediately cease injection; 

 (2) Take all steps reasonably necessary to determine whether there may have been a release of the injected carbon dioxide stream into any unauthorized zone;  (3) Notify the Director within 24 hours;  (4) Restore and demonstrate mechanical integrity to the satisfaction of the Director prior to resuming injection; and  (5) Notify the Director when injection can be expected to resume. 

Support the proposed EPA language for (1), (2), 

and (5) 

 (3) Notify the Director within 24 hours of discovery;  (4) Restore and demonstrate mechanical integrity to the satisfaction of the director as soon as practicable and prior to resuming injection. 

Needs to be reasodiscovery. It was felt that somechanical integrit

146.89 9. Mechanical integrity 

 (a) A Class VI well has mechanical 

Support the proposed EPA language. Agree with EPA’s r
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integrity if:  (1) There is no significant leak in the casing, tubing or packer; and  (2) There is no significant fluid movement into a USDW through channels adjacent to the injection well bore. 

 (b) To evaluate the absence of significant leaks under paragraph (a)(1) of this section, owners or operators must, following an initial annulus pressure test, continuously monitor injection pressure, rate, injected volumes, and pressure on the annulus between tubing and long stem casing and annulus fluid volume as specified in § 146.88(e); 

 (b) To evaluate the absence of significant leaks under paragraph (a)(1) of this section, owners or operators must, following an initial annulus pressure test, continuously monitor and record at least daily injection pressure, rate, injected volumes, and pressure on the annulus between tubing and long stem casing and annulus fluid volume as specified in §146.88 (e); 

We believe that inbe monitored but sWe further believe equipment which appropriate frequcontinuous for purp

146.89(c) (c) At least once per year, the owner 

or operator must use one of the following methods to determine the absence of significant fluid movement under paragraph (a)(2) of this section: 

 (1) A tracer survey such as oxygenactivation logging;  (2) A temperature or noise log; or  (3) A casing inspection log, if required by the Director. 

 (c) At least once per year, the owner or operator must confirm the absence of significant fluid movement under paragraph (a)(2) of this section using a method acceptable to the Director (e.g. including diagnostic surveys such as oxygen-activation logging or temperature or noise logs). Delete (1) Delete (2) Delete (3) 

Revised text sapproach and allonew technologies a
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 (d) The Director may require any other test to evaluate mechanical integrity under paragraph (a)(1) or (a)(2) of this section. Also, the Director may allow the use of a test to demonstrate mechanical integrity other than those listed above with the written approval of the Administrator. To obtain approval, the Director must submit a written request to the Administrator, which must set forth the proposed test and all technical data supporting its use. The 

Administrator must approve the request if it 

will reliably demonstrate the mechanical integrity of wells for which its use is proposed. Any alternate method approved by the Administrator will be published in the Federal Register and may be used in all States in accordance with applicable State law unless its use is restricted at the time ofapproval by the Administrator. 

Support the proposed EPA language. Agree with EPA’s r

146.89(e) (e) In conducting and evaluating the 

tests enumerated in this section or others to be allowed by the Director, the owner or operator and the Director must apply methods and standards generally accepted in the industry. When the owner or operator reports the results of mechanical integrity tests to the Director, he/she shall include a description of the test(s) and the method(s) used. In making his/her evaluation, the Director must review monitoring and other test data submitted since the previous evaluation. 

Support the proposed EPA language. Agree with EPA’s r

 (f) The Director may require additional or alternative tests if the results presented by the owner or operator under paragraph (d) of this section are not satisfactory to the Director to demonstrate that there is no significant leak in the casing, tubing or packer or significant movement of fluid into or between USDWs resulting from the injection activity as stated in paragraphs (a)(1) and (2) of this section. 

Support the proposed EPA language. Agree with EPA’s r
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146.90 10. Testing and monitoring requirements 

The owner or operator of a Class VI well must prepare, maintain, and comply with a testing and monitoring plan to verify that the geologic sequestration project is operating as permitted and is not endangering USDWs. The testing and monitoring plan must be submitted with the permit application, for Director approval, and must include a description of how the owner or operator will meet the requirements of this section. Testing and monitoring associated with geologic sequestration projects must, at a minimum, include: 

Support the proposed EPA language. Agree with EPA’s r

146.90 (a) Analysis of the carbon dioxide 

stream with sufficient frequency to yield data representative of its chemical and physical characteristics; 

 (b) Installation and use, except during well workovers as defined in § 146.86(d), of continuous recording devices to monitor injection pressure, rate and volume; the pressure on the annulus between the tubing and the long string casing; and the annulus fluid volume; 

Support the proposed EPA language in (a)  (b) Installation and use, except duringwell workovers as defined in §146.88(d), of continuous monitoring devices (including digital devices capturing periodic data) to monitor injection pressure, rate and volume; and record at least daily the pressure on the annulus between the tubing and the long string casing; 

146.86(d) does nowas apparently inte

146.90 (c) Corrosion monitoring of the well 

materials for loss of mass, thickness, cracking, pitting and other signs of corrosion must be performed on a quarterly basis to ensure that the well components meet the minimum standards for material strength and performance set forth in § 146.86(b) by:

 (c) Corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting and other signs of corrosion must be performed and recorded at least quarterly and may be modified to be less frequent as approved by the Director based on construction materials, operating conditions, and monitoring history to ensure that the well components meet the minimum standards for material strength and performance set forth in §146.86(b) by: 

Allows application Allows less freque

corrosion resistant 

146.90(c) (1) Placing coupons of the well 

construction materials in contact with the carbon dioxide stream; or 

 (2) Routing the carbon dioxide stream through a loop constructed with the material used in the well; or 

 (1) Analyzing coupons of the well construction materials placed in contact with the carbon dioxide stream; or  (2) Routing the carbon dioxide stream through a loop constructed with the material used in the well and inspecting the materials in the 

Clarification edits 
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 (3) Using an alternative method approved by the Director; 

loop; or  (3) Using an alternative method, materials, or time period approved by the Director; 

146.90(d) (d) Periodic monitoring of the 

ground water quality and geochemical changes above the confining zone(s) that may be a result of carbon dioxide movement through the confining zone or additional identified zones: 

 (1) The location and number of monitoring wells must be based on specific information about the geologic sequestration project, including injection rate and volume, geology, the presence of artificial penetrations and other factors;  (2) The monitoring frequency and spatial distribution of monitoring wells must be based on baseline geochemical data that has been collected under § 146.82(a)(6) and any modeling results in the area of review evaluation required by § 146.84(b); 

 (d) Periodic monitoring of reservoir formation fluid quality in a permeable and porous formation as near as practicable to the confining zone(s) for geochemical changes that may be a result of carbon dioxide or displaced formation fluid movement:  (1) The location and number of monitoring wells must be based on specific information about the geologic sequestration project, including injection rate and volume, geology, the presence of artificial penetrations and other relevant factors as warranted by a riskassessment;  (2) The monitoring frequency and spatial distribution of monitoring wells must be based on geological, geochemical and geophysical data that has been collected under §146.82(d) and any modeling results in the area of review evaluation required by §146.84(b); 

Drilling monitorinconsidered since pathway for movem[Geochemical data relevance in select

146.90 (e) A demonstration of external 

mechanical integrity pursuant to § 146.89(c) at least once per year throughout the duration of the geologic sequestration project; 

 (f) A pressure fall-off test at least once every five years unless more frequent testing is required by the Director based on site specific information; 

 (e) A demonstration of external mechanical integrity pursuant to §146.89(c) at least once per year until the well is plugged;  (f) A pressure fall-off test or other equivalent test that identifies reservoir conditions with respect to flow dynamics at least once every five years unless more frequent testing is required by the Director based on site specific information; 

Redundant to sect

 (g) Testing and monitoring to track the extent of the carbon dioxide plume and the position of the pressure front by either monitoring for pressure changes in the first formation overlying the confining zone or using indirect, geophysical techniques (e.g., seismic, electrical, gravity, or electromagnetic surveys and/or down-hole 

 (g) Testing and monitoring to track the extent of the carbon dioxide plume and the position of the pressure front. 

Monitoring outside little information of the injected plumemonitor could be innot be included in t
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carbon dioxide detection tools); 

146.90 (h) At the Director’s discretion, 

surface air monitoring and/or soil gas monitoring to detect movement of carbon dioxide that could endanger a USDW. 

 (h) At the Director’s discretion based on site-specific conditions and risk-based factors, surface air monitoring and/or soil gas monitoring to detect movement of carbon dioxide that could endanger a USDW. 

In most situations provide an effectiv

146.90(h) (1) The testing and monitoring plan 

must be based on potential vulnerabilities within the area of review; 

 (2) The monitoring frequency and spatial distribution of surface air monitoring and/or soil gas monitoring must reflect baseline data and the monitoring plan must include how the proposed monitoring will yield useful information on the area of review delineation and/or compliance with standards under 40 CFR 144.12; 

(1) The testing and monitoring plan must 

be based on site-specific geologic factors, modeling, and riskassessment within the area of review; 

(2) Agree with EPA language 

The GWPC feevulnerabilities” is replacing this tergeologic factors, m

146.90(i) (i) Any additional monitoring, as 

required by the Director, necessary to support, upgrade, and improve computational modeling of the area of review evaluation required under § 146.84(b) and to determine compliance with standards under 40 CFR 144.12; and 

 (j) A quality assurance and surveillance plan for all testing and monitoring requirements. 

Support the proposed EPA language. Agree with EPA’s r

146.91 11. Reporting requirements. 

The owner or operator must, at a minimum, provide the following reports to the Director, for each permitted Class VI well:  (a) Semi-annual reports containing:  (1) Any changes to the physical, chemical and other relevant characteristics of the carbon dioxide stream from the 

 (a) Semi-annual or at a frequency determined by the Director reports containing:  (1) Any significant changes to the physical, chemical and other relevant characteristics of the carbon dioxide stream from the proposed operating data; 

Should be sedetermined 
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proposed operating data;  (2) Monthly average, maximum and minimum values for injection pressure, flow rate and volume, and annular pressure; 

146.91(a) (3) A description of any event that 

exceeds operating parameters for annulus pressure or injection pressure as specified in the permit; 

 (4) A description of any event which triggers a shutdown device required pursuant to § 146.88(e) and the response taken;  (5) The monthly volume of the carbon dioxide stream injected over the reporting period and project cumulatively;  (6) Monthly annulus fluid volume added; and  (7) The results of monitoring prescribed under § 146.90. 

 (3) A description of any event that significantly exceeds operating parameters for annulus pressure or injection pressure as specified in the permit;  (4) A description of any event which triggers a shutdown device required pursuant to §146.88(e) and the response taken; 

EPA should conson reporting these would be of limited 

 (b) Report, within 30 days the results of: 

 (1) Periodic tests of mechanical integrity;  (2) Any other test of the injection well conducted by the permittee if required by the Director; and  (3) Any well workover.  (c) Owners or operators must submit reports in an electronic format acceptable to the Director. At the discretion of the Director, other formats may be accepted. 

Support the proposed EPA language. Agree with EPA’s r

146.92 12. Injection well plugging. 

 (a) Prior to the well plugging, the owner or operator must flush each Class VI injection well with a buffer fluid, determine bottomhole reservoir pressure, and perform a final mechanical integrity test. 

 (a) Prior to the well plugging, the owner or operator must flush each Class VI injection well with a buffer fluid, determine bottomhole reservoir pressure, and perform a final external mechanical integrity test. 

Many of the compointernal MIT are plugging processsuggests including for clarification. 
GWPC Recommendations Page 34 of 40 34 

Rule Provision EPA Proposal GWPC Recommendations 

146.92(b) (b) Well Plugging Plan. The owner 

or operator of a Class VI well must prepare, maintain, and comply with a plan that is acceptable to the Director. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. The well plugging plan must be submitted as part of the permit application and must include the following information: 

Support the proposed EPA language. Agree with EPA’s r

 (1) Appropriate test or measure to determine bottomhole reservoir pressure; 

 (2) Appropriate testing methods to ensure mechanical integrity as specified in § 146.89;  (3) The type and number of plugs to be used;  (4) The placement of each plug including the elevation of the top and bottom of each plug;  (5) The type and grade and quantity of material to be used in plugging. The material must be compatible with the carbon dioxide stream; and  (6) The method of placement of the plugs. 

Support the proposed EPA language for (1), (3), (4) and (6)  (2) Appropriate testing methods to ensure final external mechanical integrity as specified in §146.89(c);  (5) The type and grade and quantity of material to be used in plugging. The material must be suitable for use with the carbon dioxide stream; and 

Many of the compointernal MIT are plugging processsuggests adding tfor clarification. 

 (c) Notice of intent to plug. The owner or operator must notify the Director at least 60 days before plugging of a well. At this time, if any changes have been made to the original well plugging plan, the owner or operator must also provide the revised well plugging plan. At the discretion of the Director, a shorter notice period may be allowed. 

Support the proposed EPA language. Agree with EPA’s r

146.92(d) (d) Plugging report. Within 60 days 

after plugging or at the time of the next semi-annual report (whichever occurs earlier) the owner or operator must submit a plugging report to the Director. If the semiannual report is due less than 15 days after 

 (d) Plugging report. Within 60 days after plugging the owner or operator must submit a plugging report to the Director. The report must be certified as accurate by the owner or operator and by the person who performed the plugging 

Simplification 
GWPC Recommendations Page 35 of 40 35 

Rule Provision EPA Proposal GWPC Recommendations 

completion of plugging, then the report must be submitted within 60 days after plugging. The report must be certified as accurate by the owner or operator and by the person who performed the plugging operation (if other than the owner or operator.) 

operation (if other than the owner or operator.) 

146.93 13. Post-injection site care and site closure 

 (a) The owner or operator of a Class VI well must prepare, maintain, and comply with a plan for post-injection site care and site closure that meets the requirements of paragraph (a)(2) of this section and is acceptable to the Director.  (1) The owner or operator must submit the post-injection site care and site closure plan as a part of the permit application to be approved by the Director. 

Support the proposed EPA language Agree with EPA’s r

 (2) The post-injection site care and site closure plan must include the following information: 

 (i) The pressure differential between pre-injection and predicted post-injection pressures in the injection zone;  (ii) The predicted position of the carbon dioxide plume and associated pressure front at site closure as demonstrated in the area of review evaluation required under § 146.84(b); 

Support the proposed EPA language. Agree with EPA’s r

146.93(a)(2) (iii) A description of post-injection 

monitoring location, methods, and proposed frequency; and 

 (iv) A proposed schedule for submitting post-injection site care monitoring results to the Director. 

Support the proposed EPA language. Agree with EPA’s r

 (3) Upon cessation of injection, owners or operators of Class VI wells must either submit an amended post-injection site care and site closure plan or demonstrate to the Director through monitoring data and modeling results that no amendment to the 

Support the proposed EPA language. Agree with EPA’s r
GWPC Recommendations Page 36 of 40 36 

Rule Provision EPA Proposal GWPC Recommendations 

plan is needed. 

 (4) The owner or operator may modify and resubmit the post-injection site care and site closure plan for the Director’s approval within 30 days of such change. 

Support the proposed EPA language. Agree with EPA’s r

146.93(b) (b) The owner or operator shall 

monitor the site following the cessation of injection to show the position of the carbon dioxide plume and pressure front and demonstrate that USDWs are not being endangered. 

 (1) The owner or operator shall continue to conduct monitoring as specified in the Director-approved post-injection site care and site closure plan for at least 50 years following the cessation of injection. At the Director’s discretion, the monitoring will continue until the geologic sequestration project no longer poses an endangerment to USDWs. 

 (b) The owner or operator shall monitor the site following the cessation of injection.  (1) The owner or operator shall continue to conduct monitoring as specified in the Director-approved post-injection site care and site closure plan until closure is authorized pursuant to 146.93(b)(3). 

Eliminate the 50 yeThere is no justifprojects for the predifficult to accepperiods with the regulations. Defaincentives for best Need for site-spedata Need achievable a

146.93(b) (2) If the owner or operator can 

demonstrate to the satisfaction of the Director before 50 years, based on monitoring and other site-specific data, that the geologic sequestration project no longer poses an endangerment to USDWs, the Director may approve an amendment to the post-injection site care and site closure plan to reduce the frequency of monitoring or may authorize site closure before the end of the 50-year period. 

 (2) The owner or operator can request and demonstrate to the satisfaction of the Director that the post-injection site care and site closure plan should be revised to reduce the frequency of monitoring.

See above regapresumptive time p

 (3) Prior to authorization for site closure, the owner or operator must submit to the Director a demonstration, based on monitoring and other site-specific data, that the carbon dioxide plume and pressure front have stabilized and that no additional 

(3) Prior to authorization for site closure, 

the owner or operator must demonstrate to the Director, based on monitoring, other site-specific data, and modeling that is reasonably consistent with site performance, that no additional monitoring is needed to assure that the geologic 

The GWPC revisperformance basmonitoring period. 
GWPC Recommendations Page 37 of 40 37 

Rule Provision EPA Proposal GWPC Recommendations 

monitoring is needed to assure that the geologic sequestration project does not pose an endangerment to USDWs. 

sequestration project does not and is not expected to pose an endangerment to USDWs. The Director shall approve closure if the owner or operator demonstrates, based on the current understanding of the site, including monitoring data and/or modeling, all of the following: (i) the estimated magnitude and extent of the project footprint (CO2 plume and the area of elevated pressure) ; (ii) the estimated location of the detectable CO2 plume; (iii) that there is no significant leakage of either CO2 or displaced formation fluids that is endangering USDWs; (iv) that the injected or displaced fluids are not expected to migrate in the future in a manner that encounters a potential leakage pathway into a USDW; (v) that the injection wells at the site completed into or through the injection zone or confining zone are plugged and abandoned in accordance with these requirements; and (vi) any remaining project monitoring wells at the site are being managed by a person and in a manner acceptable to the Director. 

 (4) If such a demonstration cannot be made (i.e., if the carbon dioxide plume and pressure front have not stabilized) afterthe 50-year period, the owner or operator must submit to the Director a plan to continue post-injection site care. 

Delete No longer necess

removed. 

146.93(c) (c) Notice of intent for site closure. 

The owner or operator must notify the Director at least 120 days before site closure. At this time, if any changes have been made to the original post-injection site care and site closure plan, the owner or operator must also provide the revised plan. At the discretion of the Director, a shorter notice period may be allowed. 

No recommendation Need for site-spe

data 

146.93(d) (d) After the Director has authorized 

site closure, the owner or operator must plug all monitoring wells in a manner which will not allow movement of injection or formation fluids that endangers a USDW. 

No recommendation Need for site-spe

data 
GWPC Recommendations Page 38 of 40 38 

Rule Provision EPA Proposal GWPC Recommendations 

 (e) Once the Director has authorized site closure, the owner or operator must submit a site closure report within 90 days that must thereafter be retained at a location designated by the Director. The report must include: 

 (1) Documentation of appropriate injection and monitoring well plugging as specified in § 146.92 and paragraph (c) of this section. The owner or operator must provide a copy of a survey plat which has been submitted to the local zoning authority designated by the Director. The plat must indicate the location of the injection well relative to permanently surveyed benchmarks. The owner or operator must also submit a copy of the plat to the Regional Administrator of the appropriate EPA Regional Office; 

 (e) Once the Director has authorized site closure, the owner or operator must submit a site closure report within 90 days after completion of all closure operations. The report must include:  (1) Documentation of appropriate injection and monitoring well plugging as specified in §146.92 and paragraph (c) of this section. The owner or operator must provide a copy of a survey plat which has been submitted to the local zoning authority designated by the Director. The plat must indicate the location of the injection well(s) relative to permanently surveyed benchmarks. The owner or operator must also submit a copy of the plat to the Regional Administrator of the appropriate EPA Regional Office; 

What is the retentihave a three year is the steward of project, not the ow

 (2) Documentation of appropriate notification and information to such State, local and tribal authorities as have authority over drilling activities to enable such State and local authorities to impose appropriate conditions on subsequent drilling activities that may penetrate the injection and confining zone(s); and 

 (3) Records reflecting the nature, composition and volume of the carbon dioxide stream. 

No recommendation Need for site-spe

data 

146.93 (f) Each owner or operator of a 

Class VI injection well must record a notation on the deed to the facility property or any other document that is normally examined during title search that will in perpetuity provide any potential purchaser of the property the following information: 

 (1) The fact that land has been used to sequester carbon dioxide;  (2) The name of the State agency, local authority, and/or tribe with which the survey plat was filed, as well as the address 

No recommendation Need for site-spe

data 
GWPC Recommendations Page 39 of 40 39 

Rule Provision EPA Proposal GWPC Recommendations 

of the Regional Environmental Protection Agency Office to which it was submitted; and 

 (3) The volume of fluid injected, the injection zone or zones into which it was injected, and the period over which injection occurred. 

 (g) The owner or operator must retain for three years following site closure, records collected during the post-injection site care period. The owner or operator must deliver the records to the Director at the conclusion of the retention period, and the records must thereafter be retained at a location designated by the Director for that purpose. 

No recommendation Need for site-spe

data 

146.94 14. Emergency and remedial response. 

 (a) As part of the permit application, the owner or operator must provide the Director with an emergency and remedial response plan that describes actions to be taken to address movement of the injection or formation fluids that may cause an endangerment to a USDW during construction, operation, closure and postclosure periods. 

146.94(b) (b) If the owner or operator obtains 

evidence that the injected carbon dioxide stream and associated pressure front may cause an endangerment to a USDW, the owner or operator must: 

 (1) Immediately cease injection;  (2) Take all steps reasonably necessary to identify and characterize any release;  (3) Notify the Director within 24 hours; and  (4) Implement the emergency and 

 (b) If the owner or operator obtains evidence that the injected carbon dioxide stream, displaced formation fluids or associated pressure front endangers a USDW, the owner or operator must:  (1) Immediately cease injection;  (2) Take all steps reasonably necessary to identify and characterize the endangerment posed;  (3) Notify the Director or the designated representative within 24 hours of becoming aware of the endangerment; and 

The GWPC felt clarification since began to run for thit was felt that notthe Director wounotice. 
GWPC Recommendations Page 40 of 40 40 

Rule Provision EPA Proposal GWPC Recommendations 

remedial response plan approved by the Director. 

 (4) Implement the emergency and remedial response plan approved by the Director. 

 (c) The Director may allow the operator to resume injection prior to remediation if the owner or operator demonstrates that the injection operation will not endanger USDWs. 

 (d) The owner or operator must notify the Director and obtain his approval prior to conducting any well workover. 

Support the proposed EPA language for (c)  (d) The owner or operator must notify the Director prior to conducting any well workover in response to any case of endangerment. 

In critical situationcould adversely operations or incre
Letter ID: 0259 

Commenter: Michel Paque 

Organization: Ground Water Protection Council 

Letter ID: 0259 Comment ID: 24811 Letter Lines: 81 to 127 

Comment Code: 5610 2.11.1 Allowing partial primacy for Class VI wells (seeking comment) 

Comment: RESOLUTION 08-1 

REGARDING DELEGATION OF PRIMARY ENFORCEMENT AUTHORITY TO STATES 

FOR THE 

GEOSEQUESTRATION OF CARBON DIOXIDE 

WHEREAS, the United States Environmental Protection Agency (USEPA) has 

determined the geologic sequestration of carbon dioxide is a process that falls 

within the jurisdiction of the Safe Drinking Water Act (SDWA), Underground 

Injection Control (UIC) program; and 

WHEREAS, the USEPA has developed a proposed federal rule under the UIC program 

to regulate the practice of geologic sequestration of carbon dioxide; and 

WHEREAS, the USEPA has proposed the creation of a new injection well class for 

carbon dioxide geologic sequestration injection wells with the designation of 

Class VI; and 

WHEREAS, upon adoption of a federal rule states will lack primacy enforcement 

authority (Primacy) for Class VI wells until such authority is delegated to the 

states by USEPA; and 

WHEREAS, the USEPA has indicated the delegation of primacy for Class VI wells 

will fall under the authority of Section 1422 of the SDWA; and 

WHEREAS, it is the current practice of USEPA to only delegate primacy under 

Section 1422 of the SDWA if a state accepts primacy for all well classes other 

than Class II wells; and 

WHEREAS, it is in the best interest of protecting ground water resources for the 

geologic sequestration of carbon dioxide to be regulated at the state level; and 

WHEREAS, the GWPC is an association of state administrators of underground 

injection control and ground water protection programs that will be responsible 

for administering programs for the geologic sequestration of carbon dioxide; and 

WHEREAS, any requirement by USEPA that states accept primacy for Class I, III, 

IV and V wells, as a condition for obtaining primacy for Class VI wells will 

1
create an unreasonable burden upon states; and 

WHEREAS, any requirement by USEPA that states with primacy for Class I, III, IV 

and V wells also accept primacy for Class VI wells will compromise the states 

ability to decide how best to administer the states UIC program and may 

unnecessarily disrupt the states’ UIC program; 

NOW THEREFORE BE IT RESOLVED THAT, the GWPC recommends USEPA provide for 

the 

voluntary and separate delegation of primacy to the states for Class VI wells 

under the UIC program unless the state requests the delegation be made a part of 

a state UIC primacy program. 

Individual Response: EPA agrees that states should be allowed to obtain primacy for Class VI 

wells independently of other well classes, and will allow independent primacy for Class VI wells 

under §145.1(i) of the final GS rule. In the past, EPA has not accepted UIC primacy applications 

for individual well classes under Section 1422 of SDWA. In other words, if a State wanted 

primacy for Class I wells, the State would also need to accept responsibility for Class III, IV, and 

V wells. This policy has been in place since the initiation of the UIC Program in the early 1980s 

and was intended to encourage states to take full responsibility for UIC programs, avoid 

duplication of efforts, and provide for administrative efficiencies. 

However, given the potential for CCS (encompassing capture, transportation, and geologic 

sequestration) to be an important part of a national priority to address climate change, EPA 

believes that providing states the flexibility to obtain primacy for Class VI wells independently 

of other well classes can help foster effective management of CCS. EPA believes that allowing 

independent Class VI primacy may encourage states to take responsibility for implementation of 

Class VI regulations and provide for a more comprehensive approach to managing CCS projects 

by promoting the integration of GS activities under SDWA into a broader framework for 

managing CCS. Furthermore, GS operations involve ancillary activities (e.g., pipeline 

operations, pore space ownership, land use rights, and surface access) for which states can call 

upon other authorities that exist at the state level (but outside UIC authority) to provide a more 

comprehensive CCS management approach. 

The Agency believes that it is important for states to use their unique efficiencies to promote 

adoption of this burgeoning and important technology, while assuring that USDWs are protected 

from endangerment through the UIC regulatory framework. EPA believes that, due to the 

importance of implementing an effective, comprehensive, and seamless CCS program, States 

should be provided the flexibility to obtain primacy for Class VI only. 

EPA also believes that allowing states to apply only for Class VI primacy will shorten the 

primacy approval process for states. EPA's willingness to accept independent primacy 

applications for Class VI wells represents a shift in its longstanding policy of discouraging 

"partial primacy." It is very important to note that this shift in policy allowing for Class VI 

primacy does not apply to any other well Class under Section 1422. EPA will continue to 

discourage applications for partial primacy for all other well types under Section 1422. 

2
EPA clarifies that states should be able to obtain primacy for Class VI wells independent of other 

well classes provided they develop regulations that are at least as stringent as the minimum 

Federal requirements (e.g., permitting, inspection, operation, monitoring, and recordkeeping 

requirements) provided in the final GS rule. EPA believes that existing programs can adapt their 

expertise to the new requirements for Class VI wells and will be able to develop a primacy 

application for Class VI wells under section 1422 of SDWA and ensure that their GS programs 

integrate into national climate change priorities and protect USDWs from endangerment. 

EPA recognizes that some states have already begun legislative efforts that are wider in scope 

than the Federal GS rule and believes that allowing Class VI primacy (independent of other well 

classes) may encourage states to take responsibility for implementation of a more comprehensive 

approach to managing CCS projects (e.g., capture, transportation, and geologic sequestration). 

Letter ID: 0259 Comment ID: 24812 Letter Lines: 147 to 171 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: EPA Rule Issue: 8. Class VI requirements and permits will need to be carefully 

structured to ensure that they do not "authorize" inappropriate hazardous 

releases. This would include clarifying if there are potential releases from the 

well which are outside the scope of the Class VI permit. EPA requests comment on 

particular situations where this might occur. EPA notice 43504. 

GWPC CO2 Committee Response: CERCLA application should be avoided or sorted out 

and affirmed by Congress to indicate that it would not apply; municipal 

operators have major concern over this potential because cities will be around 

long-term and look like deep pockets 

As EPA has noted, CERCLA liability does not apply to federally permitted 

releases (FPRs), including releases covered by a UIC permit, even if GS would 

lead to a hazardous substance release. Nor should CERCLA liability apply to any 

downstream reactions or transformations resulting from FPRs. Accordingly, there 

appears to be little real potential for CERCLA liability resulting from GS. Yet 

EPA needs to clarify that CERCLA liability is extremely unlikely to result from 

any GS operation that has not injected streams that are not covered by its UIC 

permit. 

Rationale: Even the potential for CERCLA liability is viewed with such 

apprehension because of the overwhelmingly negative effects that such liability 

has had on the investing community, however, that EPA’s discussion of that 

possibility without substantial clarification is very likely to have a chilling 

effect on the support for development and deployment of CCS technologies. 

Individual Response: CERCLA exempts from liability, under CERCLA section 107, 42 U.S.C. 

3
9607, certain “federally permitted releases” (FPR) as defined in CERCLA, 42 U.S.C. 9601(10). 

Therefore, Class VI requirements and permits will need to be carefully structured to ensure that 

they do not “authorize” inappropriate releases, and would need to prevent potential releases from 

the well which are outside the scope of the Class VI permit. 

Furthermore, EPA is promulgating the GS rule under the authority of the SDWA. To the extent 

the commenter is seeking interpretations of CERCLA and its related provisions, such as the 

definition of a federally permitted release, such interpretations are beyond the scope of this 

rulemaking. 

The UIC program Director has authority under SDWA §1423 to address potential compliance 

issues (e.g., potential releases that may endanger USDWs) resulting from injection violations in 

the unlikely event that a remedial response is necessary. Although EPA anticipates that the need 

for emergency or remedial actions at GS sites will be rare, the GS rule requires, at §146.94, that 

emergency and remedial response plans be developed and updated to address such events and 

that owners or operators demonstrate that financial resources are set aside to implement the plans 

if necessary, per §146.85. 

Regarding long term liability, once an owner or operator has met all regulatory requirements 

under Part 146 for Class VI wells and the Director has approved site closure pursuant to 

requirements at §146.93, the owner or operator will generally no longer be subject to 

enforcement for regulatory noncompliance. Furthermore, their financial instrument as required 

under §146.85 will be released if it was not used. However, even if a site closure is approved 

under §146.93, an owner or operator may be held liable for regulatory noncompliance (including 

violation of 40 CFR 144.12) in certain circumstances. For example, an owner or operator may be 

held liable for regulatory noncompliance even after site closure was approved if the Director 

relied on erroneous information (e.g., erroneous modeling data) provided by the owner or 

operator when approving site closure. 

Separate from EPA’s authority to enforce regulatory compliance, an owner or operator may be 

subject to a §1431 response order even after proper site closure is approved under §146.93. 

Under §1431 the Administrator may require an owner or operator to take necessary response 

measures if he or she receives information that a contaminant is present or is likely to enter a 

public water system or an USDW, which may present an imminent and substantial endangerment 

to the health of persons, and the appropriate State and local authorities have not acted to protect 

the health of such persons. The action may include issuing administrative orders or commencing 

a civil action for appropriate relief against the owner or operator of a Class VI well. If the owner 

or operator fails to comply with the order, they may be subject to a civil penalty for each day in 

which such violation occurs or failure to comply continues. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. 

§§7401-7671; CERCLA, 42 U.S.C. §9601-9675; and RCRA, 42 U.S.C. §6901-6992. EPA does 

not have authority to transfer SDWA or other legal liability for Class VI wells to the State or 

federal government or a third-party fund. See the final rule preamble for further discussion of 

EPA's final approach. 

4
EPA adds that promoting the use of GS is outside the scope of the GS rule. Rather, the purpose 

of the GS regulation is to ensure that, where deployed, GS is conducted in a manner that protects 

USDWs from endangerment. 

Letter ID: 0259 Comment ID: 24813 Letter Lines: 173 to 182 

Comment Code: 1614 1.3.1.2 Impurities in captured CO2; purity standards for CO2 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: EPA Notice Questions: 73 FR 43504 

EPA Rule Issue: 9. EPA also requests comment on other considerations associated 

with the presence of impurities in the CO2 stream related to CERCLA. EPA Notice 

43504. 

GWPC CO2 Committee Response: The only need is to address constituents in a CO2 

stream that would defeat capture, compression, transport or GS, and these can be 

addressed through the use of special materials in many cases. The focus should 

be on compatibility rather than on any need for purification. 

Individual Response: The GS rule does not set generic purity standards for CO2 injectate 

streams (e.g., a percent CO2). Instead, the GS rule addresses the quality and quantity of 

impurities by requiring owners or operators to submit information on the source of the CO2 and 

its physical and chemical properties. Specifically, the GS rule requires the owner or operator to 

submit data about the site, including an analysis of the chemical and physical characteristics of 

the CO2 stream, as required at §146.82(a)(7)(iv), and information on the compatibility of the 

CO2 stream with fluids in the injection zone and minerals in both the injection and the confining 

zones and the materials used to construct the well, per §146.82(c)(3). This information can help 

the Director determine the potential for geochemical reactions between the injectate (CO2) and 

the host geologic formations, which could result in the plugging of pore spaces or the dissolution 

of formation minerals. 

Letter ID: 0259 Comment ID: 24814 Letter Lines: 186 to 210 

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones 

(seeking comment) 

Comment: EPA Rule Issue: 10. EPA’s proposal would provide the Director the discretion to 

require the owner or operator to identify and characterize additional confining 

and containment zones above the primary (i.e., lowermost) confining zone that 

could further impede vertical fluid movement and allow for pressure dissipation. 

EPA says that these layers could provide additional sites for monitoring, 

mitigation, and remediation. EPA’s proposal would not require that these 

additional zones be identified for all GS sites because their absence does not 

5
necessarily indicate inappropriateness of a GS site. However, if such zones are 

present, information about their characteristics can provide inputs for 

predictive models, identify appropriate monitoring locations, and improve public 

confidence in and acceptance of a proposed GS site. EPA specifically seeks 

comment on the merits of requiring the identification of these additional zones. 

EPA Notice 43506. 

GWPC CO2 Committee Response: Any showing of secondary containment is unnecessary 

once the requirement for containment has been satisfied by providing for an 

adequate confining zone. References to additional confining and containment 

zones is more likely to lead to confusion than support. 

Rationale: Any emphasis on the availability of additional confining zones is 

likely to cause confusion over the adequacy of projects that satisfy the actual 

requirements but do not also provide what is by definition redundant and 

unnecessary layers of protection. Moreover, discussions of additional confining 

zones could undercut the ability to use beneficially any additional formations 

in the area of interest covered by a proposed project. 

Individual Response: EPA retains the requirement to identify additional containment/confining 

zones, if required by the Director, as proposed (§146.83(b)). EPA acknowledges that such 

additional zones may not be needed in all circumstances, and clarifies that this requirement is at 

the Director's discretion, based on his or her understanding of a particular site. EPA believes that, 

in some situations, the presence of additional confining and containment zones above the 

primary (i.e., lowermost) confining zone can improve USDW protection. These layers could 

further impede vertical fluid movement and allow for pressure dissipation, and also provide 

additional sites for monitoring, mitigation, and remediation. The Agency's decision is supported 

by commenters representing states, water associations, and an electric utility who assert that 

these requirements promote a flexible, risk-based, site-specific approach to characterizing and 

permitting a site for GS projects, and are intended to improve understanding of the project as a 

whole and promote better modeling of the site. 

Letter ID: 0259 Comment ID: 24815 Letter Lines: 212 to 223 

Comment Code: 4460 2.4.4.4.1 Comments in favor of allowing aquifer exemptions in certain 

circumstances 

Comment: EPA Notice Questions: 73 FR 43512 

EPA Rule Issue: 25. EPA is also requesting comments on whether aquifer 

exemptions should be allowed for the purpose of Class VI injection, and under 

what conditions should such aquifer exemptions be approved. EPA Notice 43512. 

GWPC CO2 Committee Response: The committee recommends that aquifer exemptions be 

allowed. At this time, the Committee is not recommending any specific need for 

new aquifer exemption criteria created because the existing criteria are 

6
perceived to be sufficient to allow aquifer exemptions as needed for GS. Even 

without changes, the aquifer exemption requirements in the UIC program would 

allow operators to obtain appropriate exemptions for GS operations. 

Individual Response: EPA acknowledges that there are limited circumstances where aquifer 

exemptions for GS may be warranted. The final rule allows for the expansion of the areal extent 

of existing aquifer exemptions for Class II EOR/EGR wells transitioning to Class VI injection 

for GS pursuant to requirements at §§146.4 and 144.7(d). Class VI owners or operators granted 

expansions of existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of 

the tailored requirements for GS wells in the final GS rule. 

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; 

that is, aquifer exemptions will only be granted for projects that are transitioning from Class II 

EOR/EGR wells to Class VI. 

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will 

be at the Director's discretion and based on site-specific information. If an owner or operator 

applies for a Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that 

is located above and/or between USDWs, the permit applicant must also apply for a waiver of 

the injection depth requirements pursuant to §146.95 to ensure that if a waiver is granted, 

USDWs above and below the injection zone are protected from endangerment. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR 

operations and Class VI operations are considered during the aquifer exemption application 

process and the Class VI permitting process. These differences include the anticipated large CO2 

injection volumes associated with GS, the buoyant and mobile nature of the injectate, and its 

corrosivity in the presence of water. The Agency believes that this process will encourage 

owners or operators and Directors to consider the use of alternative formations for GS, including 

non-USDW formations through the waiver process, prior to applying for or approving aquifer 

exemption expansions for Class II EOR/EGR wells transitioning to Class VI GS operations. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and 

preamble, as well as EPA's responses to comments on the Notice of Data Availability and 

Request for Comment. 

Letter ID: 0259 Comment ID: 24816 Letter Lines: 225 to 237 

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth 

Comment: EPA Notice Questions: 73 FR 43512 

EPA Rule Issue: 26. EPA seeks comment on whether the Agency should set a minimum 

injection depth requirement for CO2 GS, rather than require that such injection 

take place below the lowermost USDW. EPA Notice 43512. 

GWPC CO2 Committee Response: There should not be a minimum depth established AND 

7
there should be no blanket restriction concerning proximity to USDWs but should 

instead be based on ability to protect USDWs. 

Rationale: The presence of numerous oil and gas reservoirs above demonstrates 

the ability of geologic formations at those depths to trap and contain fluids 

comparable to CO2 streams. 

Individual Response: EPA agrees that it is not appropriate to set a minimum injection depth for 

GS projects and the Agency believes that a determination of site-suitability for GS (i.e., that 

subsurface formations will receive and confine injected CO2) should be made on a site-specific 

basis. The GS rule, at §146.82, requires the owner or operator to provide extensive site- and 

project-specific information to the Director to demonstrate that the site meets the minimum site 

criteria at §146.83, that the CO2 will be contained within the injection formation, and that 

USDWs will be protected from endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost 

USDW can be performed in a manner that protects USDWs, as long as appropriate protections 

are in place. The final GS rule at §146.95 establishes a process by which owners or operators can 

seek a waiver of the Class VI injection depth requirements for injection into non-USDW 

formations above and/or between USDWs. The waiver approach requires the submission of 

extensive, site-specific information (in conjunction with the permit application submission) to 

demonstrate that injection of CO2 into a non-USDW that is above or between USDWs can be 

done in a manner that is protective of USDWs. The requirements are designed to ensure that the 

owner or operator, the Director, and the Regional Administrator consider, on a site specific basis, 

the implications, benefits, and challenges associated with GS and ensuring water availability and 

USDW protection. For additional information on the waiver approach, please see the final rule 

and preamble, as well as EPA's responses to comments on the Notice of Data Availability and 

Request for Comment. 

Letter ID: 0259 Comment ID: 24817 Letter Lines: 239 to 249 

Comment Code: 4490 2.4.5 Use of tracers and potential impact on human health or ecosystems 

(seeking comment) 

Comment: EPA Notice Questions: 73 FR 43513-15 

EPA Rule Issue: 27. EPA’s proposal allows Directors’ discretion on whether to 

require the use of tracers, and if so, what types of tracers. EPA seeks comment 

on the use of tracers in CO2 GS operations, and any potential impact of tracers 

on human health or ecosystems as they relate to USDWs. EPA Notice 43513. 

GWPC CO2 Committee Response: Due to the knowledge gaps in the use of tracers in 

this type of environment language regarding Directors discretion is OK. However, 

further research needs to be conducted before any final language to allow the 

use of tracers is approved. 

8
Individual Response: EPA agrees that the use of tracers should not be required at all GS sites, 

but should be available as an option. For this reason, EPA does not require the use of tracers at 

all GS sites; however, the Director has discretion to require their use if he/she determines that the 

use of tracers could improve monitoring of the site and enhance USDW protection from 

endangerment. The rule will also allow their use if proposed by the owner or operator and 

approved by the Director. 

EPA continues to follow new and ongoing research on the safety and efficacy of tracers. For 

example, studies at the Frio Brine Pilot Experiment site (Dayton, TX) used various types of 

tracers, including perfluorocarbon tracers (PFTs), sulfur hexafluoride, and the noble gases 

krypton, neon, and xenon. These studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; 

McCallum et al., 2005) found that tracers can provide useful CO2 monitoring information at 

injection wells at depth and at near-surface locations. At Frio, tracers enabled quantification of 

CO2 plume behavior and provided a technique for model validity testing (McCallum et al., 

2005). EPA will continue to track research related to tracer use. 

EPA has been following new and ongoing research on the safety and efficacy of tracers, 

including their efficiency and cost-effectiveness. The Agency plans to, every six years, collect 

and review data on GS projects to determine whether the appropriate amount and types of 

information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

Letter ID: 0259 Comment ID: 24818 Letter Lines: 251 to 265 

Comment Code: 4655 2.6.5.1 Plume tracking techniques/geophysical methods (seeking 

comment) 

Comment: EPA Notice Questions: 73 FR 43517 

EPA Rule Issue: 33. EPA seeks comment on the appropriate amount and types of 

monitoring that should be conducted at a GS site. Specifically, EPA seeks 

comment regarding the usefulness of indirect geophysical monitoring and surface 

air and soil gas monitoring. In addition, EPA seeks comment regarding the use of 

a Director-approved monitoring plan for GS sites. EPA Notice 43517. 

GWPC CO2 Committee Response: Although actual monitoring of injection formation 

might be considered most effective you still have the potential problem of 

putting holes in the confining formation. Perhaps the use of seismic to place 

monitoring wells into the injection zone would be an appropriate approach. The 

number of monitoring wells should not be established in advance. Obviously the 

UIC program does not have complete control over monitoring well construction or 

operation or closure. With respect to soil and air monitoring there is a 

Individual Response: The final rule (at §146.90(g)) requires owners or operators to perform 

monitoring to track the extent of the CO2 plume and pressure front. The owner or operator must 

use direct methods to monitor for pressure changes in the injection zone. Indirect methods (e.g., 

9
seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools) 

are also required unless the Director determines, based on site-specific geology, that such 

methods are not appropriate. 

Pressure monitoring within the injection zone is necessary because any such monitoring above 

the confining zone would not detect movement of the pressure front unless a breach of the 

confining zone occurs. EPA believes that monitoring using wells in the injection zone (i.e., that 

penetrate the confining zone) can be safely performed if the wells are constructed to prevent flow 

between the injection zone and USDWs or other layers above the confining zone. Such 

construction technologies exist and have been used in the oil and gas industry for years. EPA 

believes that the benefits of monitoring in the injection formation outweigh the manageable risk 

of those monitoring wells serving as conduits for fluid movement. EPA adds that owners or 

operators may consider performing additional pressure monitoring in wells that are above the 

confining zone (e.g., in the same wells used to perform ground water quality monitoring required 

at §146.90(d)) to provide additional verification that no pressure changes are occurring above the 

confining zone due to CO2 leakage. Monitoring also identifies needed remedial actions, provides 

inputs for AoR reevaluation modeling, and targets additional geochemical and surface 

monitoring needs. Knowledge of the location of the CO2 plume and the associated pressure front 

will assure the public that GS projects are proceeding according to plan, provide sufficient 

information to the owner or operator and Director, or allow for appropriate actions to address any 

indication that USDWs may be endangered. 

EPA notes that plugging of monitoring wells must be addressed as part of the post-injection site 

care and site closure plan required under §146.93. EPA is developing guidance on well 

construction that will include recommendations for monitoring well construction. The guidance 

will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA acknowledges that, at certain sites, there may be a need for more or different monitoring 

schemes (which may include monitoring in the confining zone), and adds that it is important to 

balance the need for adequate monitoring that ensures USDW protection from endangerment 

against too many artificial penetrations which could serve as conduits for fluid migration. Sitespecific testing and monitoring plans should describe the proposed monitoring regime, including 

the number and location of monitoring wells, which must be approved by the Director. 

EPA is developing guidance on testing and monitoring to assist owners or operators and 

Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. In addition, in 

January 2009, DOE published a best practices manual entitled "Monitoring, Verification, and 

Accounting of CO2 Stored in Deep Geologic Formations" (DOE/NETL-311/081508); this 

manual is included in the docket for the final GS rule. 

10
Letter ID: 0259 Comment ID: 24819 Letter Lines: 265 to 266 

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking 

comment) 

Comment: operation or closure. With respect to soil and air monitoring there is a 

question as to the efficacy of these as a means of protecting USDWs. 

Individual Response: EPA acknowledges that air and soil gas monitoring are subject to sitespecific limitations and may not be suitable in all settings as a method to ensure USDW 

protection. However, EPA does not believe that this should entirely preclude their use. If surface 

monitoring were the only monitoring method employed to ensure USDW protection, direct 

correlation of CO2 at the surface with CO2 in the subsurface might be difficult; however, when 

combined with information gathered through other monitoring techniques required of GS well 

owners and operators (e.g., monitoring wells, geophysical techniques), air and soil gas 

monitoring may provide valuable data on the magnitude and location of a leak. 

Used in conjunction with deep subsurface monitoring, as required at §146.90, and as part of a 

multi-barrier approach to protecting USDWs from endangerment, surface air and soil gas 

monitoring will increase USDW protection, enable immediate notification of the UIC Director in 

the case of potential USDW endangerment, and facilitate remedial action. 

The decision to use surface monitoring and the selection of monitoring methods will be sitespecific (e.g., may be influenced by geology, injection depth, and operational conditions) and 

must be based on potential risks to USDWs within the AoR. The final rule at §146.90(h) retains 

the allowance for surface air and soil gas monitoring at the discretion of the Director as a means 

of identifying leaks that may pose a risk to USDWs and informing emergency notification of a 

Class VI owner or operator and UIC Director in the event of a USDW endangerment, pursuant to 

requirements at §146.91(c). 

Letter ID: 0259 Comment ID: 24820 Letter Lines: 268 to 295 

Comment Code: 4750 2.7.5 Comments on the merit of annual reports (seeking comment) 

Comment: EPA Notice Questions: 73 FR 43518 

EPA Rule Issue: 37. In addition to the above recordkeeping and reporting 

requirements, EPA considered a requirement for owners or operators of GS sites 

to provide an annual report during the lifetime of the project, including the 

post-injection period, regarding the GS operation. Although EPA has not included 

a requirement for this report in its proposal, EPA seeks comment regarding the 

necessity for such an annual report. EPA Notice 43518. 

GWPC CO2 Committee Response: See Workgroup recommendation 7.6 for further 

details. 

11
Report annually, or at a frequency acceptable to the Director, the 

characteristics and cumulative volumes (annual and total) of injected fluids, 

injection pressures, injection rates, annular pressures for each injection well, 

the results of any mechanical integrity tests conducted during this time period, 

available site integrity monitoring results, the extent of the injected CO2 and 

the pressure front based on current data. 

Update site operations as appropriate and site modeling results annually, or at 

a frequency acceptable to the Director, to reflect current data. 

Compare the updated results to the previous results. Identify and explain to 

the Director any discrepancies between the updated results and the previous 

results. 

Note: Technology transfer is a better forum for driving regulatory changes. Do 

not support annual reporting as outlined in the preamble. 

Individual Response: EPA is retaining the semi-annual reporting requirements as proposed at 

§146.91(a). These requirements ensure the Director has the information needed to take 

preventive action in a timely manner to protect USDWs from endangerment. 

The final GS regulation does not include a requirement for an annual report. Instead, EPA 

believes that periodic reevaluation of the AoR, as required at §146.84(e), along with any 

revisions to the required plans that may be necessary based on the AoR reevaluation, will 

promote an ongoing relationship between the permitting authority and the owner or operator. The 

final GS rule, at §§146.84(c), 146.90(j), and 146.94(d), requires owners or operators to review 

and update the AoR and corrective action plan, the testing and monitoring plan, and the 

emergency and remedial response plan throughout the life of the project. Owners or operators 

must review each plan and identify necessary amendments to the plan or demonstrate to the 

Director that no amendment is needed. These reviews must be performed within one year of an 

AoR reevaluation, following any significant changes to the facility (e.g., the addition of 

monitoring or injection wells), or when required by the Director. In no case can reviews occur 

less often than once every five years. 

For additional information, please see the final rule and the preamble for a discussion of EPA's 

final approach to recordkeeping and reporting. 

Letter ID: 0259 Comment ID: 24821 Letter Lines: 299 to 336 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment: EPA Rule Issue: 38. EPA is proposing using a combination of fixed timeframe and 

a performance standard as described above. EPA is tentatively proposing a postinjection site care (monitoring) period of 50 years with Director’s discretion 

to change that period to lengthen or shorten the 50 year period if appropriate. 

12
EPA requests comment on the proposed use of a tentative 50 year fixed timeframe 

that could be modified at the Director’s discretion based on monitoring and 

modeling data. EPA Notice 43519. 

GWPC CO2 Committee Response: It is inappropriate to utilize a fixed period. A 

demonstration of non endangerment is an appropriate means of deciding when 

monitoring is no longer needed. The Committee recommends using a combination of 

the non-endangerment standard with specific performance standards as follows: 

Prior to authorization for site closure, the owner or operator must demonstrate 

to the Director, based on monitoring, other site-specific data, and modeling 

that is reasonably consistent with site performance, that no additional 

monitoring is needed to assure that the geologic sequestration project does not 

and is not expected to pose an endangerment to USDWs. The Director shall approve 

closure if the owner or operator demonstrates, based on the current 

understanding of the site, including monitoring data and/or modeling, all of the 

following: (i) the estimated magnitude and extent of the project footprint (CO2 

plume and the area of elevated pressure) ; (ii) the estimated location of the 

detectable CO2 plume; (iii) that there is no significant leakage of either CO2 

or displaced formation fluids that is endangering USDWs; (iv) that the injected 

or displaced fluids are not expected to migrate in the future in a manner that 

encounters a potential leakage pathway into a USDW; (v) that the injection wells 

at the site completed into or through the injection zone or confining zone are 

plugged and abandoned in accordance with these requirements; and (vi) any 

remaining project monitoring wells at the site are being managed by a person and 

in a manner acceptable to the Director. 

Rationale: The fixed timeframe is not adequately supported by scientific and 

technical evidence and represents an unnecessary departure from the use of 

performance standards, which EPA has recognized as the preferred approach in 

most other situations. The use of "stabilization" as a performance standard is 

not advised because of the difficulties of dealing with background 

movement within the injection zone. The most important demonstration is 

containment, not just movement. 

Individual Response: EPA agrees that there will be circumstances where it can be demonstrated 

in less than 50 years that the plume and pressure front no longer pose a risk of endangerment to 

USDWs. For this reason, the GS rule offers owners or operators flexibility regarding the duration 

of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC 

timeframe during the post-injection period based on site-specific data, pursuant to requirements 

at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator 

to demonstrate, during the permitting process based on substantial data, that an alternative PISC 

timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to 

requirements at §146.93(c). 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

13
for post-injection site care will be necessary in most cases. The default 50 year post-injection site 

care timeframe represents a reasonable and protective monitoring period based on a review of 

research studies, industry reports, and existing environmental programs, and evaluation of public 

comments. 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

Letter ID: 0259 Comment ID: 24822 Letter Lines: 338 to 368 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: EPA Notice Questions: 144.36 

EPA Rule Issue: 41. Current UIC guidance describes trust funds as a form of 

financial assurance. The owner or operator may deposit funds into the trust fund 

in phases; that is, either over the term of the initial permit or over the 

remaining operating life of the injection well, as estimated in the well 

plugging plan, whichever period is shorter. Because of the possibility that the 

owner or operator may face financial distress prior to the trust being fully 

funded, EPA is considering a guidance approach that would recommend adopting a 

pay in period of three years for GS projects, consistent with other similar 

programs in the Agency. EPA Notice 43521. 

GWPC CO2 Committee Response: The Committee recommends that financial assurance 

requirements be based on costing of plans, with updating as appropriate to 

account for changed conditions and modified plans. The methods of providing FA 

should remain flexible, as EPA has proposed, to allow markets to adapt to the 

requirements and to identify methods for providing FA. Under any circumstances, 

EPA should continue to use self-insurance mechanisms through a financial test. 

Any development of guidance for specific FA instruments should await the initial 

experience with those instruments, but would probably be addressed better 

through guidance than regulations to maintain a greater amount of flexibility to 

adapt to changes in the market that are likely to follow increased understanding 

of the technologies involved and operating experience with those technologies. 

All FA requirements should be released at closure. 

Rationale: For any particular instrument, the pay-in period should be 

commensurate with the risk profile. i.e. greater risk = faster pay-in. 

14
The plans should be updated as appropriate in conjunction with the iterative 

process of AoR reevaluations using data from monitoring and operational 

experience to reevaluate the modeling. 

Individual Response: Owners or operators may choose from a variety of financial instruments 

to meet their financial responsibility obligations under the rule, provided the Director determines 

that the operator's proposed financial responsibility demonstration is adequate to protect USDWs 

from endangerment, which means the ability of the owner or operator to pay for each activity for 

which financial responsibility must be demonstrated, including corrective action on wells in the 

AoR, injection well plugging, PISC and site closure, and emergency and remedial response 

throughout the life of the project. The final GS rule specifies at §146.85(a)(1) the permitted types 

of financial responsibility instruments. See the final rule and preamble for further discussion of 

EPA's final approach to financial responsibility. 

EPA will retain self insurance as an option for financial responsibility for Class VI wells. EPA 

believes that if properly used, the financial test can be an appropriate option for some owners or 

operators. EPA recognizes that it is important for self-insurers to be credit-worthy, otherwise 

USDWs may not be adequately protected. Owner or operators who choose to self-insure and use 

the financial test must be able to demonstrate profitability, with a margin sufficient to cover 

contingencies and unknown obligations, and stability. If the owner or operator meets corporate 

financial test criteria, this is an indication that the owner or operator can guarantee its ability to 

satisfy financial obligations based solely on the strength of the company’s financial condition. If 

an operator or operator is not able to meet the corporate financial test criteria may arrange a 

corporate guarantee by demonstrating that its corporate parent meets the financial requirements 

on its behalf. 

EPA acknowledges that there may be several possible approaches to setting pay-in periods for 

trust funds. The final rule requires that the Director approve the use and length of pay-in periods. 

EPA is developing guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) that describes the types of 

financial instruments that owners or operators can use to meet financial responsibility 

requirements for GS wells. Specifically, the guidance will discuss pay-in periods and provide 

guidance for Directors to use in determining an appropriate pay-in period. EPA adds that owners 

or operators may choose from a variety of financial instruments to meet their financial 

responsibility needs. 

EPA also agrees that it is important to periodically update cost estimates that support financial 

responsibility determinations. EPA clarifies that the GS rule, at §146.85(c), requires the owner or 

operator to provide annual updates to the cost estimate to account for any amendments to the 

AoR and corrective action plan, the injection well plugging plan, the PISC and site closure plan, 

and the emergency and remedial response plan. The owner or operator must also adjust the cost 

estimate annually for inflation. EPA adds that the Director can also require the owner or operator 

to provide an adjustment of the cost estimate if the Director determines that the original 

demonstration is no longer adequate, as specified at §146.85(e). 

15
Letter ID: 0259 Comment ID: 24823 Letter Lines: 370 to 408 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: EPA Notice Questions: 73 FR 43521 

EPA Rule Issue: 42. Current UIC regulations for Class I hazardous waste 

injection allow for the use of insurance for purposes of demonstrating financial 

responsibility. However, insurance was not included as part of the guidance 

provided for Class II injection because this insurance mechanism was and still 

is, rarely used for the purpose of demonstrating financial assurance for 

injection wells. EPA is assessing whether to provide guidance on the use of 

insurance providers and, if so, whether to update eligibility requirements for 

insurers for GS wells consistent with other current Federal agency practices. 

EPA Notice 43521. 

GWPC CO2 Committee Response: Leave the door open for establishing financials 

mechanisms on a project by project basis. The rulemaking should not prescribe 

or preclude particular financial instruments. The issue of financial assurance 

is complex and must be considered in significant detail and should be based on 

the initial experience gained from the use of FA mechanisms before any guidance 

or regulation is issued. 

EPA Notice Questions: 73 FR 43522 

EPA Rule Issue: 43. EPA is assessing whether a financial ratings threshold for 

all companies using a self-guarantee, similar to those used by other Federal 

agencies, is appropriate. The Agency also is considering what constitutes an 

appropriate financial rating threshold, and whether a financial rating greater 

than BBB or Baa (i.e., the current rating threshold established under the UIC 

regulations) is appropriate for GS wells. EPA Notice 43522. 

GWPC CO2 Committee Response: See response to #41. 

EPA Notice Questions: 146.85 

EPA Rule Issue: 44. EPA is requesting comments on whether financial 

responsibility mechanisms to be recommended in EPA guidance should be adjusted 

in the manner described, whether additional instruments should be included, and 

whether other adjustments to the financial responsibility mechanisms should be 

considered, all subject to EPA’s authority under the SDWA. EPA Notice 43522. 

GWPC CO2 Committee Response: See response to #41 

Individual Response: As described above, owners or operators may choose from a variety of 

16
financial instruments listed in §146.85(a) to meet their financial responsibility obligations, 

provided the Director determines that the operator's proposed financial responsibility 

demonstration is adequate to prevent endangerment of USDWs by demonstrating the ability to 

pay for each activity for which financial responsibility must be demonstrated, including 

corrective action on wells in the AoR, injection well plugging, PISC and site closure, and 

emergency and remedial response. 

Letter ID: 0259 Comment ID: 24824 Letter Lines: 410 to 423 

Comment Code: 5436 2.9.1.3 Allowing separate financial demonstrations for plugging and 

abandonment and post-injection site care (seeking comment) 

Comment: EPA Notice Questions: 73 FR 43522 

EPA Rule Issue: 45. The Agency is also requesting comment on allowing separate 

financial demonstrations to be submitted for the plugging of the injection well 

and for the post-injection site care requirements. EPA Notice 43522. 

GWPC CO2 Committee Response: The Committee supports the use of separate 

financial demonstrations for the plugging of the injection well and for the 

post-injection site care requirements based on the greater experience with well 

plugging requirements and methods. It will be easier to retain certainty for 

these actions and to use established FA methods. 

Rationale: EPA should look into the options available for single bonding with 

phased release and multiple bonding, as is done under SMCRA. 

Individual Response: EPA will allow owners or operators to use separate or multiple financial 

responsibility instruments for different GS activities. However, owners or operators must 

demonstrate adequate financial responsibility for all required activities with their permit 

applications per §146.82(a)(14). In addition, on an annual basis, the owner or operator must 

adjust the cost estimate for inflation, increase or decrease the value of the financial instrument to 

match the cost estimate, and provide any updated information related to their financial 

responsibility instrument(s), or at any other time deemed appropriate by the Director. These 

annual reviews provide a mechanism for revising cost estimates up or down to account for 

changes in the project, including the execution of environmental obligations as phases of a GS 

project are completed. 

EPA is developing guidance on financial responsibility for Class VI wells. The guidance will 

include a discussion on how best to estimate costs to assist Class VI well owners or operators, 

third party insurers or providers of financial instruments, and permitting authorities in 

developing estimates of the costs associated with various GS activities. EPA will also discuss 

approaches to evaluate the appropriateness of single and multiple bonding and phased release of 

bonds in the guidance. EPA will review the requirements under SMCRA as it develops the 

guidance and incorporate any relevant information. This guidance will be available on EPA's 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

17
Letter ID: 0259 Comment ID: 24825 Letter Lines: 425 to 437 

Comment Code: 5520 2.10.1 Appropriateness of existing public participation requirements 

(Part 25 and Part 124) for GS (seeking comment) 

Comment: EPA Notice Questions: 73 FR 43523 

EPA Rule Issue: 46. EPA requests comment on adopting the existing requirements 

for public participation at 40 CFR Part 25 and 40 CFR Part 124 and whether 

additional requirements should be included to reflect the availability of new 

tools for disseminating and gathering information. Such tools include cable 

networks, the Internet, and other new technology. EPA Notice 43523. 

GWPC CO2 Committee Response: Public participation requirements for Class VI well 

permitting should follow established requirements for UIC program permitting, 

which have proven successful. Any modifications to account for technological 

advances should be considered on a program-wide basis; there is nothing unique 

about GS in this respect. 

Individual Response: EPA agrees that the existing UIC public participation requirements as 

specified in 40 CFR 25 and 40 CFR 124 are appropriate for GS projects. In addition, because of 

the unique nature of GS projects, and the anticipated level of public interest in GS projects, EPA 

is not requiring the use of new information technologies, but encourages GS operators to use new 

information technologies whenever possible to keep the public informed of GS projects. EPA 

encourages early public involvement in GS projects. Providing the public with accurate, project 

specific information in the early stages of each GS project can help clarify project details and 

avoid public misperceptions about the nature and safety of GS projects, and will allow a potential 

GS owner or operator and the permitting agency to address the public's concerns before the 

permitting process is complete. 

In response to the suggestion to apply additional public participation requirements to all injection 

well classes, EPA notes that this is beyond the scope of the GS rulemaking. 

Letter ID: 0259 Comment ID: 24826 Letter Lines: 439 to 454 

Comment Code: 5560 2.10.3 Enhancing the public participation process (seeking comment) 

Comment: EPA Notice Questions: 73 FR 43522-23 

EPA Rule Issue: 47. EPA also requests comment on ways to enhance the public 

participation process, including engaging communities in the site 

characterization process as soon as candidate locations are identified. EPA 

Notice 43523. 

18
GWPC CO2 Committee Response: This is best left up to the discretion of the 

regulator. Establishing a process may provide a standard that can be followed by 

developers. There was concern about the term "as soon as". If included, this 

term should be changed to a more reasonable period following applicant 

evaluation of a site. Public participation requirements should be similar to 

other portions of the UIC program (e.g. Class I). The program should assure a 

public hearings process when warranted by substantive issues and affected 

stakeholders but the timing and particulars of the process should not be 

prescribed in the rule. 

Individual Response: The Agency believes that public participation is an important part of the 

UIC permitting process and wants to ensure wide access to decision-making processes and 

information on projects that may affect the public. GS permitting authorities must follow the 

existing public participation requirements for UIC permits as specified in 40 CFR Part 124. 

Generally, these regulations require the Director to notify the public regarding the availability of 

the draft permit and allow him or her to request a public hearing on the draft permit. 

Furthermore, §124.12(a) requires the Director to hold a public hearing whenever he or she finds 

based on received comments articulating a significant degree of public interest in a draft permit. 

EPA encourages operators and permitting agencies to begin involving the public by providing 

information as early in the process as possible. Such information exchange can affect how the 

local community and surrounding communities perceive potential environmental, economic, or 

health effects. 

Letter ID: 0259 Comment ID: 24827 Letter Lines: 473 to 493 

Comment Code: 5610 2.11.1 Allowing partial primacy for Class VI wells (seeking comment) 

Comment: EPA Notice Questions: 73 FR 43523 

EPA Rule Issue: 49. There may be benefits to parsing out primacy for Class VI 

wells, however EPA has not made a decision on this. Allowing States, 

Territories, and Tribes to acquire primacy for only Class VI wells may encourage 

them to assume the responsibility of implementation and provide for a more 

comprehensive approach to managing CCS projects (e.g., capture, transportation, 

and geologic sequestration). EPA is seeking comment on the merits and possible 

disadvantages of allowing primacy approval for Class VI wells independent of 

other well classes. EPA Notice 43523. 

GWPC CO2 Committee Response: Resolution 08-1 of the GWPC strongly urges USEPA to 

allow for the granting of individual primacy to states for the Class VI program. 

We further support the preservation of state authority to determine what 

agencies will exercise primacy, strongly urge USEPA to provide adequate funding, 

which will require a substantial increase above current funding levels both to 

meet both existing UIC program needs and the additional resources anticipated to 

19
be necessary for the Class VI program. Ramp up of resources, personnel, and 

training should precede anticipated heavy demand. 

Rationale: Submit GWPC resolution 08-1 

Individual Response: As described above, EPA agrees with commenters that states should be 

allowed to obtain primacy for Class VI wells independently of other well classes, and will allow 

independent primacy for Class VI wells under §145.1(i) of the final GS rule. 

EPA acknowledges that there may be technical and administrative challenges including resource 

concerns, and will work closely with the states to assist them in resolving funding issues or 

acquiring the resources, personnel, and training needed to address the unique technical 

challenges associated with GS. 

EPA will also incorporate Class VI wells into the UIC Program's grant allocation process. The 

States/Tribes/Territories must also demonstrate that they have adequate resources to implement 

the program through matching resources against those allocated by the UIC Program's grant 

allocation formula. Currently, primacy programs are required to meet a minimum of 25 percent 

matching requirement. 

Letter ID: 0259 Comment ID: 24828 Letter Lines: 495 to 514 

Comment Code: 6220 3.2.2 Assumptions about the number of monitoring wells (seeking 

comment) 

Comment: EPA Notice Questions: 73 FR 43527 

EPA Rule Issue: 51. The Agency assumes three monitoring wells per injection well 

for the purpose of estimating national costs; however, the Agency recognizes 

that operators and primacy agency Directors may choose more or fewer monitoring 

wells depending on project site characteristics. Because the monitoring wells 

and associated costs represent a significant component of the Cost Analysis, the 

Agency acknowledges that this factor may be significant in the overall 

uncertainty of the Cost Analysis. EPA requests comment on whether three 

monitoring wells per injection well is an appropriate costing assumption. EPA 

Notice 43527. 

GWPC CO2 Committee Response: The group is unsure as to EPA’s methodology for 

deciding on the number of monitoring wells since each project could be vastly 

different requiring a wide variety in numbers and types of any necessary 

monitoring wells. Also, it was felt that the statement regarding the fact that 

monitoring wells are a significant portion of the costs has not been supported 

by independent analysis as yet. Therefore, the issue of numbers of monitoring 

wells is not yet ripe for a decision. 

20
Individual Response: EPA recognizes that the number of monitoring wells associated with GS 

projects will be site-specific and vary based on many factors, including the local geologic 

characteristics, the presence of other injection wells, the size of the AoR, and volumes of CO2 

injected. The proposed rule Cost Analysis described the number of monitoring wells as a ratio to 

the number of injection wells; EPA clarifies that the number of injection wells was based on the 

size of the AoR and the type of project. Therefore, the number of monitoring wells was indirectly 

based on the size of the AoR. Because ER project sites have injection wells that are more 

clustered than those in saline formations, the AoR and the number of monitoring wells were 

anticipated to be smaller at an ER project site compared to a saline formation project. EPA 

retained this assumption regarding the density of injection wells for the final rule analysis, but it 

changed its assumption on the number of monitoring wells at each site. For the final rule, the 

Agency assumes one monitoring well above the injection zone per two square miles of AoR; for 

monitoring wells into the injection zone, the Agency assumes one monitoring well per four 

square miles. EPA assumes monitoring wells into the injection zone will also be used to sample 

above the injection zone. The number of monitoring wells assumed for each project type is 

presented in Exhibit 5.2 of the Cost Analysis. 

Because the actual number of monitoring wells that will be necessary for a given project site is 

uncertain, EPA tested the sensitivity of overall cost estimates to the number of monitoring wells 

by applying a 25 percent decrease and increase in monitoring wells per project type to the 

original assumptions. This change results in annualized incremental rule costs approximately 16 

percent less and 16 percent greater than costs estimated for the primary analysis (as shown in 

Exhibit 5.26 of the Cost Analysis). For additional information on EPA's final regulatory 

approach, including testing and monitoring requirements, please see the final rule and preamble. 

EPA is developing guidance on monitoring and testing to assist owners/operators and Directors 

in evaluating requirements under §146.90, including developing determining the appropriate 

number of monitoring wells for a GS site. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24829 Letter Lines: 515 to 517 

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 

CFR 146.90) 

Comment: There should not be a requirement for monitor wells into the injection zone, and 

monitor wells should not be required for the purpose of tracking the plume or 

pressure front. 

Individual Response: EPA maintains that plume tracking and pressure monitoring are key 

components of monitoring at GS sites. A rigorous plume tracking and pressure monitoring 

scheme, such as one that meets the requirements at §146.90(g), is imperative for ensuring that 

the CO2 plume is contained within the injection zone. The final GS rule, at §146.90(g)(1), 

requires GS well owners or operators to use direct methods to monitor for pressure changes in 

the injection zone. The purpose of monitoring in the injection zone is to track the development 

21
and movement of the pressure front and CO2 plume. This will support an understanding of site 

performance and verify predictive modeling. Pressure monitoring within the injection zone is 

necessary because any such monitoring above the confining zone would not detect movement of 

the pressure front unless a breach of the confining zone occurs. 

Letter ID: 0259 Comment ID: 24830 Letter Lines: 519 to 528 

Comment Code: 7700 4.7 Executive Order 13045: Children's Health Protection 

Comment: EPA Notice Questions: 73 FR 43531 

EPA Rule Issue: 52. The public is invited to submit comments or identify peerreviewed studies and data that assess the effects of early life exposure to 

changes in drinking water quality that may be caused by geologic sequestration 

of carbon dioxide. EPA Notice 43531. 

GWPC CO2 Committee Response: Studies already exist that address potential 

exposure issues, but there should be a recognition of the very low potential for 

exposure that exists for GS projects. 

Individual Response: EPA is funding research related to the potential for USDW contamination 

associated with GS projects. In addition, the Agency is tracking external research that focuses on 

potential exceedances of drinking water standards, which were developed by EPA and take into 

account impacts on children's health. 

In the August 31, 2009, Notice of Data Availability (NODA) and Request for Comment (74 FR 

44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory 

(LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of 

CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, 

mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL 

estimated the amount of trace elements from native mineral species that could potentially be 

mobilized by the intrusion of CO2 and the potential ground water concentrations that could result 

to determine the potential for drinking water standards to be exceeded. EPA has also examined 

potential methods for conducting treatment of water affected by a CO2 leak; this study is 

presented in the final rulemaking docket. 

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and 

Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University 

to investigate the potential for GS to affect USDWs. This research will involve laboratory 

experiments and modeling simulations to investigate the fate of dissolved CO2 in underground 

geologic formations and to determine possible risks associated with the dissolution of CO2 in 

underground aquifers. This STAR Grant is among six such grants awarded to major universities 

and institutions focusing on: "Integrated Design, Modeling and Monitoring of Geologic 

Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water." 

EPA clarifies that the purpose of the GS rule is to protect USDWs from endangerment through 

22
permitting, siting, construction, operation, injection, and post-injection site care and site closure 

requirements that are tailored to address the unique nature of GS. The Class VI requirements, 

therefore, minimize health risks to all populations, including children. The "Risk and Occurrence 

Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, 

presents a broad discussion of risks to human health and the environment associated with GS, 

including those addressed under SDWA authority and those environmental and human health 

impacts that are beyond the scope of the SDWA. 

As part of its adaptive rulemaking approach, EPA plans to collect and review available 

information such as the research described above and data every six years on early GS projects, 

including impacts to USDWs and drinking water quality that may affect the health of children, to 

determine whether the appropriate amount and types of information and documentation are being 

collected, and to determine if modifications to the requirements are appropriate or necessary. 

Letter ID: 0259 Comment ID: 24831 Letter Lines: 539 to 547 

Comment Code: 1000 1. General and Administrative Comments 

Comment: Rule Provision: Part 144 

EPA Proposal:1. The authority citation for part 144 continues to read as 

follows: 

Authority: 42 U.S.C. 300f et seq.; Resource Conservation and Recovery Act, 42 

U.S.C. 6901 et seq. 

GWPC Recommendations: No comment necessary 

Individual Response: EPA acknowledges the comment. The final rule retains this text. 

Letter ID: 0259 Comment ID: 24832 Letter Lines: 549 to 573 

Comment Code: 2020 1.5.1 Support Class VI designation 

Comment: Rule Provision: 144.1 

EPA Proposal:2. Section 144.1 is amended as follows: 

Adding new paragraph (f)(1) (viii); and b. Revising the first two sentences in 

paragraph (g) introductory text. 

* * * * * 

(f) * * * 

23
(1) * * * 

(viii) Subpart H of this part sets forth requirements for owners or operators of 

Class VI injection wells. 

* * * * * 

(g) Scope of the permit or rule requirement. The UIC Permit Program regulates 

underground injections by six classes of wells (see definition of "well 

injection," § 144.3). The six classes of wells are set forth in § 144.6. All 

owners or operators of these injection wells must be authorized either by permit 

or rule by the Director. * * * 

GWPC Recommendations: Support revision to include a sixth class of wells. 

Individual Response: EPA agrees that tailored requirements for Class VI wells are necessary to 

address the unique nature of injecting large volumes of CO2 and to ensure that USDWs are 

protected from endangerment. The GS rule contains tailored requirements for the permitting, 

geologic site characterization, AoR and corrective action, well construction, operation, 

mechanical integrity testing, monitoring, well plugging, post-injection site care, and site closure 

of GS wells that directly address issues unique to the nature of large-scale CO2 injection for GS. 

Letter ID: 0259 Comment ID: 24833 Letter Lines: 575 to 611 

Comment Code: 2000 1.5 Need for a New Class of Injection Well 

Comment: Rule Provision: 144.6 

EPA Proposal: 3. Section 144.6 is amended as follows: 

Revising paragraph (e); and 

b. Adding new paragraph (f). 

* * * * * 

(e) Class V. Injection wells not included in Class I, II, III, IV, or VI. 

Specific types of Class V injection wells are described in § 144.81. 

(f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath 

the lowermost formation containing a USDW. 

GWPC Recommendations: (4) For enhanced recovery of oil or natural gas where 

geologic sequestration is occurring during or in connection with enhanced 

recovery of oil or natural gas provided (i) there is reasonable expectation of 

24
more than insignificant future production volumes or rates as a result of carbon 

dioxide injection and (ii) operating pressures are no higher than reasonably 

necessary to produce such volumes or rates; 

(f) Class VI. Wells injecting a carbon dioxide stream for geologic 

sequestration except those wells described in subsection (b)(4) of this section 

or otherwise excluded from this Class. 

Rationale: There should not be a blanket prohibition concerning injection above 

USDW’s or at specific levels. The determination of injection zones should be 

based upon appropriate containment. This is especially true in light of recent 

calls for changes in the definition of a USDW to include formations greater than 

10K PPM TDS and the fact that several states including Wyoming and California 

might be prevented from instituting geologic sequestration as a practical matter 

if injection were limited to above USDW’s due to the great depth of some USDW’s. 

This would create a situation where otherwise good injection zones are 

artificially excluded, thus decreasing the overall availability of geologic 

sequestration in the U.S. 

Individual Response: EPA acknowledges that there are limited circumstances where injection 

above the lowermost USDW can be performed in a manner that protects USDWs. The final GS 

rule at §146.95 establishes a process by which owners or operators can seek a waiver of the Class 

VI injection depth requirements. The waiver approach requires the submission of extensive, sitespecific information (in conjunction with the permit application submittal) to demonstrate that 

injection of CO2 into a formation that is above or between USDWs can be done in a manner that 

is protective of USDWs. The requirements are designed to ensure the owner or operator, the 

Director, and the Regional Administrator consider, on a site specific basis, the implications, 

benefits, and challenges associated with GS and ensuring water availability and USDW 

protection. 

Letter ID: 0259 Comment ID: 24835 Letter Lines: 613 to 621 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: The GWPC also recommends EPA consider retaining all geologic sequestration in 

oil and gas reservoirs under the jurisdiction of Class II UIC programs and 

create a subclass within this program for geologic storage of carbon dioxide. 

This subclass (Class II GS) would be used for those wells that depart from the 

traditional uses of Class II wells for enhanced recovery, and result in the 

application of Class VI standards. This change would eliminate any confusion 

over whether a Class II CO2 injection well used for enhanced recovery might also 

need a Class VI permit and would avoid the need to change jurisdiction for a 

well from one state agency to another over time. 

25
Individual Response: EPA disagrees that the risks posed by long term storage of CO2 for GS 

can be addressed under existing UIC requirements, such as those for Class II wells. EPA believes 

and the administrative record supports that there are significant differences between how EOR 

and GS projects are operated, as well as the different risks posed by these different injection 

activities. The new tailored approach of the GS rule was designed to address the general risks 

deep injection may pose to USDWs and was tailored specifically to address the risks posed by 

long term storage of CO2 (i.e., very large volumes, very long time-periods, and reservoir 

pressure conditions). 

In response to the comment on the burden of changing regulatory agencies in the middle of an 

operation, EPA clarifies that primacy is granted to a state, not to a specific agency within that 

state, and states may choose which agency implements the Class VI program. States may, for 

example, choose an environmental quality protection agency (non-Class II) or the state's 

traditional oil and gas regulatory agency to implement the Class VI program as long as the 

program meets the minimum federal requirements for Class VI wells as required under section 

1422 of SDWA. Some states manage all injection well classes under Section 1422 and through a 

single agency, while in other states, Class II programs are run by oil and gas agencies. 

Regardless of the specific Agency the state selects to assume regulatory authority for Class VI 

operations, the state must obtain primacy for the 1422 Class VI program. Furthermore, the state 

may determine that a memorandum of understanding (MOU) between several state agencies 

regarding specific projects can facilitate this process without needing to change regulatory 

agencies after Class II projects have transitioned to a Class VI permit. 

Letter ID: 0259 Comment ID: 24836 Letter Lines: 625 to 647 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 2048 1.5.2.4 Oppose Class VI/ Support Class V experimental technology well 

Comment: EPA Proposal: 4. Adding § 144.15 to read as follows. 

§ 144.15 Prohibition of non-experimental Class V wells for geologic 

sequestration. 

The construction, operation or maintenance of any non-experimental Class V 

geologic sequestration well is prohibited. 

GWPC Recommendations: This provision should be deleted if EPA does limit Class 

VI wells to injection below the lowermost USDW in the final rule to allow 

Directors to selectively authorize GS in areas with USDWs below the injection 

zone. 

In addition, it is recommended that all GS into basalts, coal seams, salt domes, 

and shales be conducted under Class V as experimental wells initially and then 

as commercial scale Class V wells/projects if the experimental projects 

26
demonstrate that these sites can be suitable for geological sequestration while 

preventing endangerment of USDWs. 

Rationale: Keeping these wells under Class V would allow EPA and the states to 

gain enough experience to develop suitable permitting requirements for such 

wells and to tailor those requirements until the agencies are ready to adapt the 

Class VI regulations. 

Individual Response: The text at 144.15 is retained in the final regulation; the construction, 

operation or maintenance of any non-experimental Class V GS well is prohibited under the final 

rule. The final rule contains tailored requirements for Class VI wells to ensure that GS projects 

are permitted sited, constructed, operated, and closed in a manner that does not endanger 

USDWs. 

EPA also clarifies that the final GS rule does not categorically preclude injection of CO2 into 

any formation types. Existing experimental GS projects may be permitted as described in UIC 

Program Guidance #83: Using the Class V Experimental Technology Well Classification for 

Pilot Carbon Geologic Sequestration Projects, which provided information for permitting 

authorities to consider when permitting experimental GS projects (i.e., those projects that are 

designed to test new, unproven technologies, per the definition of a Class V experimental 

technology well). EPA adds that, following finalization of the GS rule, all GS projects that are 

not for experimental purposes must be re-permitted as Class VI wells and be subject to the final 

GS requirements. EPA expects that, after promulgation of the final rule, a limited number of 

experimental injection projects to test GS technology will continue, e.g., to inform the 

technology associated with GS into basalts, coal seams, and salt domes. 

The Agency also clarifies that it does not consider it appropriate to permit CO2 injection wells 

that are testing the injectivity or appropriateness of an individual formation (e.g., as a prelude to 

a commercial-scale operation) as Class V experimental technology wells. Such wells must be 

permitted as Class VI wells. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental 

technology well classification to clarify permitting for Class V wells. This addendum will 

address shifting of Class V experimental projects to full-scale GS projects and the future use of 

the Class V experimental technology well subclass for research and testing of new GS 

technologies. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24837 Letter Lines: 649 to 660 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment: Rule Provision: 144.18 

EPA Proposal: 5. Adding § 144.18 to read as follows. 

27
§ 144.18 Requirements for class VI wells. 

Owners or operators of Class VI wells must obtain a permit. Class VI wells are 

not authorized by rule to inject. 

GWPC Recommendations: Support the proposed language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. For additional information on EPA's 

final regulatory approach, please see the final rule and preamble as well as the rulemaking 

docket. 

Letter ID: 0259 Comment ID: 24838 Letter Lines: 662 to 681 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3500 2.2.3 Area of Review Reevaluation (seeking comment) 

Comment Code: 5700 2.12 Comments on the proposed duration of Class VI permits (seeking 

comment) 

Comment: Rule Provision: 144.36 

EPA Proposal: 6. Section 144.36 is amended by revising the first two sentences 

in paragraph (a) to read as follows: 

§ 144.36 Duration of permits. 

(a) Permits for Class I and V wells shall be effective for a fixed term not to 

exceed 10 years. UIC Permits for Class II, III and VI wells shall be issued for 

a period up to the operating life of the facility. * * * 

* * * * * 

GWPC Recommendations: Support the proposed language. 

Rationale: The proposed provision is considered acceptable as long as the 

iterative reevaluation process established for AoRs also applies to other 

aspects of the project including modeling, characterization, operational 

decisions, monitoring, financial assurance, etc. It is recognized that 

Directors may also depend on 144.39 regarding modification and revocation of 

Class VI permits. 

Individual Response: EPA acknowledges the commenter’s support and notes that the final rule 

retains this requirement. The final rule maintains the lifetime permit provision and clarifies that 

the permit extends through the post-injection site care period (144.36(a)). It also adds a 

requirement that the Director review each Class VI permit at least once every 5 years to 

determine whether it should be modified, revoked and reissued, terminated or a minor 

28
modification made as provided in §§144.39, 144.40, or 144.41. The Director’s review will be 

informed by the owners’ or operators’ iterative reevaluation of the project. Specifically, the final 

rule includes a requirement that the AoR be reevaluated at least every five years, and also 

requires owners or operators to review and update the AoR and corrective action plan, the testing 

and monitoring plan, and the emergency and remedial response plan throughout the life of the 

project (146.84(e), 146.90(j), and 146.94(d)). Owners or operators must review each plan and 

identify necessary amendments or demonstrate to the Director that no amendment is needed. In 

no case can reviews occur less often than once every five years. The iterative process and 

subsequent plan reevaluations ensure that time and resources are committed to the most critical 

aspects of the permit in preventing endangerment to USDWs. EPA believes that the iterative 

process of developing and executing the various plans required of GS well operators in the final 

rule (e.g., for AoR and corrective action, testing and monitoring, injection well plugging, postinjection site care, and emergency and remedial response) is tailored to the unique aspects of—

and is more appropriate for–GS than establishing a finite permit duration. 

EPA emphasizes that the final rule requires owners or operators to revise their cost estimates for 

financial assurance within 60 days of amendments to the AoR and corrective action plan, the 

injection well plugging plan, the post-injection site care and site closure plan, or the emergency 

and remedial response plan (40 CFR 146.85(c)(2). 

EPA emphasizes that, the Director has the authority to revise the permit if project operations 

change or if the Director believes based on monitoring or operational data that the project may 

endanger USDWs. EPA has also added text to 144.39(a)(5) that permit modifications would be 

required if the Director determines that a modification is necessary based on an AoR 

reevaluation, amendments to any of the project plans, or a review of the testing and monitoring 

results. The Director may also choose to require minor permit modifications under 40 CFR 

144.41, depending on the extent of the plan amendment. All permit modifications, except minor 

modifications under 40 CFR 144.41, require an opportunity for public comment on the portion of 

the permit that is being reopened pursuant to requirements under 40 CFR Part 124. 

Letter ID: 0259 Comment ID: 24839 Letter Lines: 683 to 693 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5900 2.14 Other administrative requirements under 40 CFR 144 

Comment: EPA Proposal: 7. Section 144.39 is amended by revising the second sentence in 

paragraph (a) introductory text and by revising the second sentence in paragraph 

(a)(3) introductory text to read as follows: 

§ 144.39 Modification or revocation and reissuance of permits. 

* * * * * 

GWPC Recommendations: Support the proposed language. 

Rationale: Agree with EPA’s rationale. 

29
Individual Response: EPA acknowledges the comment. Please see the remainder of EPA's 

responses to this comment letter for further details. For additional information on EPA's final 

regulatory approach, please see the final rule and preamble as well as the rulemaking docket. 

Letter ID: 0259 Comment ID: 24840 Letter Lines: 695 to 711 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5900 2.14 Other administrative requirements under 40 CFR 144 

Comment: Rule Provision: 144.39 

EPA Proposal: (a) * * * For Class I hazardous waste injection wells, Class 

II, Class III or Class VI wells the following may be causes for revocation and 

reissuance as well as modification; and for all other wells the following may be 

cause for revocation or reissuance as well as modification when the permittee 

requests or agrees. * * * 

* * * * * 

(3) * * * Permits other than for Class I hazardous waste injection wells, 

Class II, Class III or Class VI wells may be modified during their terms for 

this cause only as follows: * * * * * * * * 

GWPC Recommendations: Support the proposed language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. Please see the remainder of EPA's 

responses to this comment letter for further details. For additional information on EPA's final 

regulatory approach, please see the final rule and preamble as well as the rulemaking docket. 

Letter ID: 0259 Comment ID: 24842 Letter Lines: 748 to 757 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5900 2.14 Other administrative requirements under 40 CFR 144 

Comment: EPA Proposal: (2) When the Director determines that a Class I, II, III or VI 

well lacks mechanical integrity pursuant to § 146.8 or § 146.89 for Class VI of 

this chapter, he/she shall give written notice of his/ her determination to the 

owner or operator. * * * 

* * * * * 

30
GWPC Recommendations: Support the proposed language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. Please see the remainder of EPA's 

responses to this comment letter for further details. For additional information on EPA's final 

regulatory approach, please see the final rule and preamble as well as the rulemaking docket. 

Letter ID: 0259 Comment ID: 24843 Letter Lines: 759 to 778 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5900 2.14 Other administrative requirements under 40 CFR 144 

Comment: Rule Provision: 144.52 

EPA Proposal: 9. Section 144.52 is amended by revising paragraph (a)(8) to 

read as follows: 

§ 144.52 Establishing permit conditions. 

(a) * * * 

(8) Mechanical integrity. A permit for any Class I, II, III or VI well or 

injection project which lacks mechanical integrity shall include, and for any 

Class V well may include, a condition prohibiting injection operations until the 

permittee shows to the satisfaction of the Director under § 146.08 or § 146.89 

for Class VI that the well has mechanical integrity. 

* * * * * 

GWPC Recommendations: Support the proposed language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. Please see the remainder of EPA's 

responses to this comment letter for further details. For additional information on EPA's final 

regulatory approach, please see the final rule and preamble as well as the rulemaking docket. 

Letter ID: 0259 Comment ID: 24844 Letter Lines: 780 to 796 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5900 2.14 Other administrative requirements under 40 CFR 144 

31
Comment: Rule Provision: 144.55 

EPA Proposal: § 144.55 Corrective action. 

(a) Coverage. Applicants for Class I, II, (other than existing), III or VI 

injection well permits shall identify the location of all known wells within the 

injection well’s area of review which penetrate the injection zone, or in the 

case of Class II wells operating over the fracture pressure of the injection 

formation, all known wells within the area of review penetrating formations 

affected by the increase in pressure. Applicants for Class VI shall perform 

corrective action as specified in § 146.84.* * * 

* * * * * 

GWPC Recommendations: Support the proposed language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. Please see the remainder of EPA's 

responses to this comment letter for further details. For additional information on EPA's final 

regulatory approach, please see the final rule and preamble as well as the rulemaking docket. 

Letter ID: 0259 Comment ID: 24845 Letter Lines: 798 to 840 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: Rule Provision: 144.80 

EPA Proposal: 11. Section 144.80 is amended by revising the first sentence in 

paragraph (e) and by adding paragraph (f)to read as follows: 

§ 144.80 What is a Class V injection well? * * * * * 

(e) Class V. Injection wells not included in Class I, II, III, IV or VI. * * 

* 

(f) Class VI. Wells used for geologic sequestration of carbon dioxide. 

GWPC Recommendations: (4) For enhanced recovery of oil or natural gas where 

geologic sequestration is occurring during or in connection with enhanced 

recovery of oil or natural gas provided (i) there is reasonable expectation of 

more than insignificant future production volumes or rates as a result of carbon 

32
dioxide injection and (ii) operating pressures are no higher than reasonably 

necessary to produce such volumes or rates; 

(f) Class VI. Wells injecting a carbon dioxide stream for geologic 

sequestration except those wells described in subsection (b)(4) of this section 

or otherwise excluded from this Class. 

Rationale: There should not be a blanket prohibition concerning injection above 

USDW’s or at specific levels. The determination of injection zones should be 

based upon appropriate containment. This is especially true in light of recent 

calls for changes in the definition of a USDW to include formations greater than 

10K PPM TDS and the fact that several states including Wyoming and California 

might be prevented from instituting geologic sequestration as a practical matter 

if injection were limited to above USDW’s due to the great depth of some USDW’s. 

This would create a situation where otherwise good injection zones are 

artificially excluded, thus decreasing the overall availability of geologic 

sequestration in the U.S. 

The GWPC also recommends EPA consider retaining all geologic sequestration in 

oil and gas reservoirs under the jurisdiction of Class II UIC programs and 

create a subclass within this program for geologic storage of carbon dioxide. 

This subclass (Class II GS) would be used for those wells that depart from the 

traditional uses of Class II wells for enhanced recovery, and result in the 

application of Class VI standards. This change would eliminate any confusion 

over whether a Class II CO2 injection well used for enhanced recovery might also 

need a Class VI permit and would avoid the need to change jurisdiction for a 

well from one state agency to another over time. 

Individual Response: EPA acknowledges that there are limited circumstances where injection 

above the lowermost USDW can be performed in a manner that protects USDWs from 

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 

establishes a process by which owners or operators can seek a waiver of the Class VI injection 

depth requirements for injection into non-USDW formations above and/or between USDWs. It 

establishes: 1) requirements specifying information that owners or operators must submit, and 

Directors must consider, in consultation with PWSS Directors; 2) procedures for public notice of 

a waiver application and for Director-Regional Administrator communication; 3) the waiver 

issuance process; and, 4) additional requirements that apply to owners or operators of Class VI 

wells granted a waiver of the injection depth requirements to ensure USDW protection above and 

below the injection zone. 

EPA adds that it has revised the definition of a Class VI well to read as follows: “Wells that are 

not experimental in nature that are used for geologic sequestration of carbon dioxide beneath the 

lowermost formation containing a USDW; or, wells used for geologic sequestration of carbon 

dioxide that have been granted a waiver of the injection depth requirements pursuant to 

requirements at §146.95 of this chapter; or, wells used for geologic sequestration of carbon 

dioxide that have received an expansion to the areal extent of an existing Class II enhanced oil 

33
recovery or enhanced gas recovery aquifer exemption pursuant to §§146.4 of this chapter and 

144.7(d).” 

For additional information on the waiver approach, please see the final rule and preamble, as 

well as EPA's responses to comments on the Notice of Data Availability and Request for 

Comment. 

In response to the comment that GS wells should be regulated as Class II wells, EPA believes 

that injection for the primary purpose of long term storage is sufficiently different from Class II 

ER operations and warrants tailored requirements. For example, the volume of CO2 anticipated 

to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure 

conditions will also be different, with Class VI injection operations involving large volumes of 

CO2 and likely having higher pressures within their storage formations than Class II ER projects. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. EPA is developing guidance on transitioning permits 

from Class II to Class VI. The guidance will assist Directors in determining whether an injection 

project should be transitioned from Class II where the primary purpose is oil and gas production 

to Class VI where the primary purpose is long-term storage of large volumes of CO2. This 

guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA also recognizes that there is increasing demand for water resources and that technology 

improvements may make high TDS aquifers viable drinking water sources. However, EPA is not 

changing the USDW definition; changing the definition of a USDW is outside the scope of the 

GS rulemaking. The GS rule focuses on ensuring protection of USDWs, as required under the 

SDWA, by establishing regulations to ensure the safe injection of CO2 for long-term storage. 

Letter ID: 0259 Comment ID: 24846 Letter Lines: 832 to 840 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: The GWPC also recommends EPA consider retaining all geologic sequestration in 

oil and gas reservoirs under the jurisdiction of Class II UIC programs and 

create a subclass within this program for geologic storage of carbon dioxide. 

This subclass (Class II GS) would be used for those wells that depart from the 

traditional uses of Class II wells for enhanced recovery, and result in the 

application of Class VI standards. This change would eliminate any confusion 

over whether a Class II CO2 injection well used for enhanced recovery might also 

need a Class VI permit and would avoid the need to change jurisdiction for a 

well from one state agency to another over time. 

34
Individual Response: EPA disagrees that the risks posed by long term storage of CO2 for GS 

can be addressed under existing UIC requirements, such as those for Class II wells. EPA believes 

and the administrative record supports that there are significant differences between how EOR 

and GS projects are operated, as well as the different risks posed by these different injection 

activities. The new tailored approach of the GS rule was designed to address the general risks 

deep injection may pose to USDWs and was tailored specifically to address the risks posed by 

long term storage of CO2 (i.e., very large volumes, very long time-periods, and reservoir 

pressure conditions). 

In response to the comment on the burden of changing regulatory agencies in the middle of an 

operation, EPA clarifies that primacy is granted to a state, not to a specific agency within that 

state, and states may choose which agency implements the Class VI program. States may, for 

example, choose an environmental quality protection agency (non-Class II) or the state's 

traditional oil and gas regulatory agency to implement the Class VI program as long as the 

program meets the minimum federal requirements for Class VI wells as required under section 

1422 of SDWA. Some states manage all injection well classes under Section 1422 and through a 

single agency, while in other states, Class II programs are run by oil and gas agencies. 

Regardless of the specific Agency the state selects to assume regulatory authority for Class VI 

operations, the state must obtain primacy for the 1422 Class VI program. Furthermore, the state 

may determine that a memorandum of understanding (MOU) between several state agencies 

regarding specific projects can facilitate this process without needing to change regulatory 

agencies after Class II projects have transitioned to a Class VI permit. 

Letter ID: 0259 Comment ID: 24847 Letter Lines: 713 to 746 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 144.51 

EPA Proposal: 8. Section 144.51 is amended by revising the first sentence in 

paragraph (q)(1) and the first sentence in paragraph (q)(2) to read as follows: 

§ 144.51 Conditions applicable to all permits. 

* * * * * 

(q) * * * 

(1) The owner or operator of a Class I, II, III or VI well permitted under this 

part shall establish mechanical integrity prior to commencing injection or on a 

schedule determined by the Director. Thereafter the owner or operator of Class 

I, II, and III wells must maintain mechanical integrity as defined in § 146.8 

and the owner or operator of Class VI wells must maintain mechanical integrity 

35
as defined in § 146.89 of this chapter. * * * 

GWPC Recommendations: (q) * * * 

(1) The owner or operator of a Class I, II, III or VI well permitted under this 

part shall establish mechanical integrity prior to commencing injection or on a 

schedule determined by the Director. Thereafter the owner or operator of Class 

I, II, and III wells must maintain mechanical integrity as defined in §146.8 and 

the owner or operator of Class VI wells must maintain mechanical integrity as 

defined in §146.89 of this chapter. 

Rationale: EPA may want to reconsider the use of the term "or" as this implies 

that an initial MIT can be optional based on Directors discretion which 

contradicts 146.89 with respect to Class VI wells. Alternatively, the two 

provisions can be read together to require an initial MIT and to give the 

Director limited discretion to allow the scheduling of the initial MIT after 

some injection has occurred, such as may be required during initial testing of 

the well and injection zone. 

Individual Response: EPA disagrees that the suggested edit is needed, and clarifies that all 

owners or operators must demonstrate internal and external mechanical integrity prior to 

commencing injection as required at §146.87(a)(4). 

Letter ID: 0259 Comment ID: 24848 Letter Lines: 842 to 851 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5900 2.14 Other administrative requirements under 40 CFR 144 

Comment: Rule Provision: Part 146 

EPA Proposal: 12. The authority citation for part 146 continues to read as 

follows: 

Authority: Safe Drinking Water Act 42, U.S.C. 300f et seq.; Resource 

Conservation and Recovery Act, 42 U.S.C. 6901 et seq. 

GWPC Recommendations: Support the proposed language. 

Individual Response: EPA acknowledges the comment. Please see the remainder of EPA's 

responses to this comment letter for further details. For additional information on EPA's final 

regulatory approach, please see the final rule and preamble as well as the rulemaking docket. 

36
Letter ID: 0259 Comment ID: 24849 Letter Lines: 854 to 896 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: Rule Provision: 146.5 

EPA Proposal: 13. Section 146.5 is amended as follows: 

a. Revising the first sentence in paragraph (e) introductory text; and 

b. Adding paragraph (f). 

(f) Class VI. Wells used for geologic sequestration of carbon dioxide beneath 

the lowermost formation containing an underground source of drinking water 

(USDW). 

GWPC Recommendations: (4) For enhanced recovery of oil or natural gas where 

geologic sequestration is occurring during or in connection with enhanced 

recovery of oil or natural gas provided (i) there is reasonable expectation of 

more than insignificant future production volumes or rates as a result of carbon 

dioxide injection and (ii) operating pressures are no higher than reasonably 

necessary to produce such volumes or rates; 

(f) Class VI. Wells injecting a carbon dioxide stream for geologic 

sequestration except those wells described in subsection (b)(4) of this section 

or otherwise excluded from this Class. 

Rationale: There should not be a blanket prohibition concerning injection above 

USDW’s or at specific levels. The determination of injection zones should be 

based upon appropriate containment. This is especially true in light of recent 

calls for changes in the definition of a USDW to include formations greater than 

10K PPM TDS and the fact that several states including Wyoming and California 

might be prevented from instituting geologic sequestration as a practical matter 

if injection were limited to above USDW’s due to the great depth of some USDW’s. 

This would create a situation where otherwise good injection zones are 

artificially excluded, thus decreasing the overall availability of geologic 

sequestration in the U.S. 

The GWPC also recommends EPA consider retaining all geologic sequestration in 

oil and gas reservoirs under the jurisdiction of Class II UIC programs and 

create a subclass within this program for geologic storage of carbon dioxide. 

This subclass (Class II GS) would be used for those wells that depart from the 

traditional uses of Class II wells for enhanced recovery, and result in the 

application of Class VI standards. This change would eliminate any confusion 

37
over whether a Class II CO2 injection well used for enhanced recovery might also 

need a Class VI permit and would avoid the need to change jurisdiction for a 

well from one state agency to another over time. 

Individual Response: Please see the response to the commenter’s suggested revision to §144.80. 

Letter ID: 0259 Comment ID: 24850 Letter Lines: 888 to 896 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: The GWPC also recommends EPA consider retaining all geologic sequestration in 

oil and gas reservoirs under the jurisdiction of Class II UIC programs and 

create a subclass within this program for geologic storage of carbon dioxide. 

This subclass (Class II GS) would be used for those wells that depart from the 

traditional uses of Class II wells for enhanced recovery, and result in the 

application of Class VI standards. This change would eliminate any confusion 

over whether a Class II CO2 injection well used for enhanced recovery might also 

need a Class VI permit and would avoid the need to change jurisdiction for a 

well from one state agency to another over time. 

Individual Response: EPA disagrees that the risks posed by long term storage of CO2 for GS 

can be addressed under existing UIC requirements, such as those for Class II wells. EPA believes 

and the administrative record supports that there are significant differences between how EOR 

and GS projects are operated, as well as the different risks posed by these different injection 

activities. The new tailored approach of the GS rule was designed to address the general risks 

deep injection may pose to USDWs and was tailored specifically to address the risks posed by 

long term storage of CO2 (i.e., very large volumes, very long time-periods, and reservoir 

pressure conditions). 

In response to the comment on the burden of changing regulatory agencies in the middle of an 

operation, EPA clarifies that primacy is granted to a state, not to a specific agency within that 

state, and states may choose which agency implements the Class VI program. States may, for 

example, choose an environmental quality protection agency (non-Class II) or the state's 

traditional oil and gas regulatory agency to implement the Class VI program as long as the 

program meets the minimum federal requirements for Class VI wells as required under section 

1422 of SDWA. Some states manage all injection well classes under Section 1422 and through a 

single agency, while in other states, Class II programs are run by oil and gas agencies. 

Regardless of the specific Agency the state selects to assume regulatory authority for Class VI 

operations, the state must obtain primacy for the 1422 Class VI program. Furthermore, the state 

may determine that a memorandum of understanding (MOU) between several state agencies 

regarding specific projects can facilitate this process without needing to change regulatory 

agencies after Class II projects have transitioned to a Class VI permit. 

38
Letter ID: 0259 Comment ID: 24851 Letter Lines: 898 to 915 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment: Rule Provision: Part 146 Subpart H 

EPA Proposal: 14. Subpart H is added to read as follows: 

Subpart H - Criteria and Standards Applicable to Class VI Wells 

Sec. 

146.82 Required Class VI permit information. 

146.83 Minimum criteria for siting. 

146.84 Area of review and corrective action. 

146.85 Financial responsibility. 

146.86 Injection well construction requirements. 

146.87 Logging, sampling, and testing prior to injection well operation. 

GWPC Recommendations: Support the proposed language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. For additional information on EPA's 

final regulatory approach, please see the final rule and preamble as well as the rulemaking 

docket. 

Letter ID: 0259 Comment ID: 24852 Letter Lines: 927 to 944 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment: EPA Proposal: (b) This subpart applies to wells used to inject carbon dioxide 

specifically for the purpose of geologic sequestration, i.e., the long-term 

containment of a gaseous, liquid or supercritical carbon dioxide stream in 

subsurface geologic formations. 

GWPC Recommendations: (b) This subpart applies to wells used to inject carbon 

dioxide streams into saline formations for the purpose of geologic 

sequestration, i.e., the long-term containment of a carbon dioxide stream in 

subsurface geologic formations. 

Rationale: Use of the term "specifically" was removed as it implied Class VI 

wells could not be used for multiple purposes and still be Class VI 

Remove "gaseous, liquid or supercritical" as these terms are implied by the use 

39
of the term carbon dioxide. 

See the rationale discussion under 146.85 regarding inclusion or exclusion of 

the term "saline" 

Individual Response: EPA disagrees with the suggested change. EPA believes that this 

paragraph, along with the definition of a CO2 stream at §146.81(d), appropriately convey the 

allowable injection activities that may be permitted as Class VI. For additional information on 

EPA's final regulatory approach, please see the final rule and preamble as well as the rulemaking 

docket. 

Letter ID: 0259 Comment ID: 24853 Letter Lines: 946 to 964 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment) 

Comment: EPA Proposal: (c) This subpart applies to owners and operators of permit or 

rule-authorized Class I industrial, Class II, or Class V experimental carbon 

dioxide injection projects who seek to apply for a Class VI geologic 

sequestration permit for their well or wells. If the Director determines that 

USDWs will not be endangered, such wells are exempt, at the Director’s 

discretion, from the casing and cementing requirements at §§ 146.86(b) and 

146.87(a)(1) through (3). 

GWPC Recommendations: (c) This subpart applies to owners and operators of permit 

or rule-authorized Class I industrial, Class II, or Class V experimental carbon 

dioxide injection projects who seek to apply for a Class VI geologic 

sequestration permit for their well or wells or to convert to Class II GS 

operation. If the Director determines that USDWs will not be endangered, such 

wells are exempt, at the Director’s discretion, from such Class VI requirements 

contained in this subpart as the Director specifies. 

Rationale: The proposed EPA waiver applies only to the casing and cementing 

requirements. Directors should have the flexibility to waive other requirements 

as appropriate for conversions to Class VI. 

Individual Response: EPA disagrees with commenters who suggest that other requirements 

(outside of well construction) should also be grandfathered. Following re-permitting of the 

project as GS, many of the unique factors of GS sites (e.g., increased reservoir pressures 

associated with large volumes of stored CO2 and the corrosivity of CO2 in the presence of 

water) will result in an increased risk profile, warranting the specific requirements in the final GS 

rule. Therefore, following re-permitting as Class VI wells, these projects must be subject to the 

operational, MIT, monitoring, reporting, plugging, and post-injection site care and site closure 

requirements in the final GS rule. See the discussion of EPA's final regulatory approach in the 

preamble to the GS rule for additional detail on these requirements. 

40
Letter ID: 0259 Comment ID: 24854 Letter Lines: 966 to 989 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3200 2.2 Proposed Area of Review and Corrective Action Requirements (40 

CFR 146.84) 

Comment: Rule Provision: 146.81(d) Definitions 

EPA Proposal: (d) Definitions. The following definitions apply to this 

subpart. To the extent that these definitions conflict with those in § 146.3 

these definitions govern: 

Area of review means the region surrounding the geologic sequestration project 

that may be impacted by the injection activity. The area of review is based on 

computational modeling that accounts for the physical and chemical properties of 

all phases of the injected carbon dioxide stream. 

GWPC Recommendations: Area of review means the subsurface three-dimensional 

extent of the carbon dioxide stream plume associated pressure front, and 

displaced brine, as well as the overlying formations and surface area above that 

delineated region. 

Rationale: Suggest removal of the second sentence and replacement with : "It 

includes the subsurface three-dimensional extent of the carbon dioxide plume, 

associated pressure front, and displaced brine, as well as the surface area 

above that delineated region." 

Comment on the inclusion of the word "surrounding" because the AoR should be coextensive with the area defined by the Carbon Sequestration Project. Inclusion 

of "surrounding" makes this definition open-ended and ambiguous. 

Individual Response: Based on review of all public comments on the AoR definition at 

146.84(a), the Agency has modified it to read as follows: The region surrounding the geologic 

sequestration project where USDWs may be endangered by the injection activity. The area of 

review is delineated using computational modeling that accounts for the physical and chemical 

properties of all phases of the injected CO2 stream and is based on available site 

characterization, monitoring, and operational data. The definition in the proposed rule accounted 

for the varying physical and chemical properties of the CO2 including free-phase and waterdissolved CO2, as the commenter suggests. The definition in the final rule will continue to do so. 

EPA is developing guidance on AoR and corrective action at GS Class VI sites to assist owners 

or operators and Directors in evaluating requirements and proposed AoR and corrective action 

plans under 146.84. The guidance describes EPA's recommended approaches for the data to be 

considered in an initial AoR delineation, how to apply computational modeling to delineate the 

AoR, performing corrective action at GS sites, and, when appropriate, completing AoR 

reevaluations. The guidance will be available on EPA's web site, at 

41
http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24855 Letter Lines: 991 to 1005 ; 1011 to 1011 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment: EPA Proposal: Carbon dioxide plume means the underground extent, in three 

dimensions, of an injected carbon dioxide stream. 

Carbon dioxide stream means carbon dioxide that has been captured from an 

emission source (e.g., a power plant), plus incidental associated substances 

derived from the source materials and the capture process, and any substances 

added to the stream to enable or improve the injection process. This subpart 

does not apply to any carbon dioxide stream that meets the definition of a 

hazardous waste under 40 CFR part 261. 

GWPC Recommendations: Carbon dioxide stream means carbon dioxide, plus 

associated substances derived from the source materials and any processing, and 

any substances added to the stream to enable or improve the injection process. 

This subpart does not apply to any carbon dioxide stream that meets the 

definition of a hazardous waste under 40 CFR part 261. 

Source of CO2 should not be an issue in the context of defining the CO2 stream. 

Individual Response: The final GS rule retains the definition of a CO2 stream as proposed. The 

GS regulation applies to injection of CO2 for the purpose of GS, regardless of the source of the 

CO2. It is beyond the scope of the GS rule and the UIC Program’s authority to require or set 

standards for upstream generators of CO2 or purification facilities. For purposes of GS, the UIC 

program’s authority under the SDWA is limited to ensuring that GS projects are sited, 

constructed, operated, and closed in a manner that protects USDWs. The GS rule does not apply 

to generators of CO2. Additionally, EPA has received numerous comments regarding the 

applicability of the RCRA regulations and statute to CO2 streams that are geologically 

sequestered under the final Class VI UIC well requirements. As a result, EPA has decided to 

initiate a separate proposed rulemaking specifically to examine the issue of RCRA applicability 

to CO2 streams being geologically sequestered, including the possible option of a conditional 

exemption from the RCRA requirements for CO2 GS in Class VI wells. EPA will consider these 

comments as part of its development of that proposal. The Agency will consider issues particular 

to RCRA in the context of that separate rulemaking, and recommends that the commenter read 

that proposed rule when it is published. The Agency notes that commenters who wish to submit 

comments on the RCRA proposal will need to do so during the comment period for that rule. 

Finally, EPA also notes that the final GS rule, which adds new regulations for Class VI wells 

under the Safe Drinking Water Act (SDWA), is not making any changes to the RCRA 

regulations. 

42
Letter ID: 0259 Comment ID: 24856 Letter Lines: 1007 to 1009 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

Comment: Rationale: Insert the definition "Computational modeling means a mathematical 

model that is appropriate to the site geometry and takes into account the 

differences between the formation and injection fluids." 

Individual Response: The final rule does not define computational modeling. The preamble to 

the proposed GS regulation and the modeling background document "Computational Modeling 

of Underground Injection of Carbon Dioxide for Determination of Area-of-Review and Potential 

Risk to Underground Sources of Drinking Water" (cited in the proposed rule preamble as 

USEPA, 2008d include FR citation) discuss, in detail, what EPA believes constitutes a 

computational model. Appropriate models may incorporate numerical, analytical, or semianalytical approaches. These models solve a series of governing equations to predict the 

composition and volumetric fraction of each phase state, as well as fluid pressures, as a function 

of location and time for a particular set of conditions. EPA is developing guidance on AoR and 

corrective action at GS Class VI sites to assist owners or operators and Directors in evaluating 

requirements and proposed AoR and corrective action plans under 146.84. The guidance 

describes the data that EPA recommends to be considered in an initial AoR delineation, how to 

apply computational modeling to delineate the AoR, performing corrective action at GS sites, 

and, when appropriate, completing AoR reevaluations. The guidance will be available on EPA's 

web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24857 Letter Lines: 1013 to 1023 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment: EPA Proposal: Confining zone means a geologic formation, group of formations, or 

part of a formation stratigraphically overlying the injection zone that acts as 

a barrier to fluid movement. 

GWPC Recommendations: Confining zone means a geological formation, group of 

formations, or part of a formation that is capable of limiting fluid movement 

from an injection zone. 

Rationale: The current UIC program definition of confining zone is preferable to 

the proposed definition. There are no special circumstances for CO2 streams 

that warrant a change 

Individual Response: EPA acknowledges the comment and the final rule retains this text as 

proposed. EPA believes that the definitions used for injection zone and confining zone for Class 

43
VI GS are appropriately tailored to address the unique risks and challenges posed by GS of CO2 

streams. 

Letter ID: 0259 Comment ID: 24858 Letter Lines: 1025 to 1031 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3400 2.2.2 Corrective Action 

Comment: EPA Proposal: Corrective action means the use of Director approved methods to 

assure that wells within the area of review do not serve as conduits for the 

movement of fluids into underground sources of drinking water (USDW). 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the commenter’s support; the final GS rule retains the 

definition. 

Letter ID: 0259 Comment ID: 24859 Letter Lines: 1033 to 1039 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment: GWPC Recommendations: "Fault means a surface or zone of rock fracture along 

which 

there has [or has not] been displacement." 

Rationale: Add definition of fault to clarify use in other provisions. This is 

the current definition with the insertion of the words "or has not" before 

displacement to recognize that faults can exist where there has been no 

displacement. 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

rule and NODA and Response to Comments EPA has made many revisions to the GS Rule. See 

the final rule and the discussion of site characterization in the preamble for further discussion on 

EPA's final approach. EPA does not define "fault" but defines "transmissive fault or fracture." 

EPA has retained the proposed definition, which is the same as the existing definition at §148.2, 

to address transmissive faults and fractures that extend beyond the confining zone. 

Letter ID: 0259 Comment ID: 24860 Letter Lines: 1041 to 1050 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

44
Comment: EPA Proposal: Geologic sequestration means the long-term containment of a 

gaseous, liquid or supercritical carbon dioxide stream in subsurface geologic 

formations. This term does not apply to its capture or transport. 

GWPC Recommendations: Geologic sequestration means the long-term containment of 

a carbon dioxide stream in subsurface geologic formations. This term does not 

apply to its capture or transport. 

Rationale: Suggest removing "gaseous, liquid or supercritical" as these terms 

are implied by the use of the term carbon dioxide. 

Individual Response: EPA disagrees with the suggested edit. However, the Agency has 

modified the definition of geologic sequestration at §146.81(d) to read as follows: “[T]he longterm containment of a gaseous, liquid, or supercritical carbon dioxide stream in subsurface 

geologic formations. This term does not apply to carbon dioxide capture or transport.” 

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0259 Comment ID: 24861 Letter Lines: 1052 to 1065 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: EPA Proposal: Geologic sequestration project means an injection well or wells 

used to emplace a carbon dioxide stream beneath the lowermost formation 

containing a USDW. It includes the subsurface three-dimensional extent of the 

carbon dioxide plume, associated pressure front, and displaced brine, as well as 

the surface area above that delineated region. 

GWPC Recommendations: Geologic sequestration project means an injection well or 

wells used to emplace a carbon dioxide stream into an injection zone for 

geologic sequestration. 

Rationale: Replace "beneath the lowermost formation containing a USDW "with 

"into an injection zone" 

Suggest moving the second sentence to the definition of AOR. 

Individual Response: In the final rule, EPA revised the definition of a geologic sequestration 

project to account for the new requirements to include “wells used for geologic sequestration of 

carbon dioxide that have been granted a waiver of the injection depth requirements pursuant to 

requirements at §146.95.” 

45
Letter ID: 0259 Comment ID: 24862 Letter Lines: 1069 to 1072 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: GWPC Recommendation: Geologic sequestration site means 

Rationale: The GWPC believes a definition for this term is needed as the term is 

referenced in later sections of the rule. 

Individual Response: EPA disagrees that a definition of geologic sequestration site is needed. 

EPA notes that a geologic sequestration site, under §146.83(a), comprises: “(1) An injection zone 

of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated 

volume of the carbon dioxide stream; [and] (2) Confining zones free of transmissive faults or 

fractures and of sufficient areal extent and integrity to contain the injected carbon dioxide stream 

and displaced formation fluids and allow injection at proposed maximum pressures and volumes 

without initiating or propagating fractures in the confining zone(s).” 

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0259 Comment ID: 24863 Letter Lines: 1074 to 1084 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: EPA Proposal: Injection zone means a geologic formation, group of formations, or 

part of a formation that is of sufficient a real extent, thickness, porosity, 

and permeability to receive carbon dioxide through a well or wells associated 

with a geologic sequestration project. 

GWPC Recommendations: Injection zone means a geological "formation", group of 

formations, or part of a formation receiving fluids through a well. 

Rationale: Existing definition in the CFR is sufficient and does not need to be 

changed. Furthermore, adding sufficiency is not a definitional issue and should 

be dealt with elsewhere. 

Individual Response: EPA disagrees with the suggested edit. The final definition of injection 

zone at §146.81(d) remains unchanged and reads as follows: “[A] geologic formation, group of 

formations, or part of a formation that is of sufficient areal extent, thickness, porosity, and 

permeability to receive carbon dioxide through a well or wells associated with a geologic 

sequestration project.” 

Based on its evaluation of all public comments and input on the proposed rule and the NODA, 

46
and Request for Comment EPA has made many revisions to the GS rule. Please see the final rule 

and preamble for additional information. 

Letter ID: 0259 Comment ID: 24864 Letter Lines: 1086 to 1095 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment: EPA Proposal: Post-injection site care means appropriate monitoring and other 

actions (including corrective action) needed following cessation of injection to 

assure that USDWs are not endangered as required under § 146.93. 

GWPC Recommendations: Post-injection site care means monitoring and other 

actions (including corrective action) following cessation of injection, as 

required under 146.93. 

Rationale: The definition should explain the meaning and not impose substantive 

requirements. These requirements are already addressed in other sections. 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

rule and NODA and Request for Comment, EPA has made many revisions to the GS Rule. See 

the final rule and preamble for further discussion on EPA's final approach. 

Letter ID: 0259 Comment ID: 24865 Letter Lines: 1097 to 1111 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: EPA Proposal: Pressure front means the zone of elevated pressure that is created 

by the injection of carbon dioxide into the subsurface. For the purposes of 

this subpart, the pressure front of a carbon dioxide plume refers to a zone 

where there is a pressure differential sufficient to cause the movement of 

injected fluids or formation fluids into a USDW. 

GWPC Recommendations: Pressure front means the zone of elevated pressure that is 

created by the injection of the carbon dioxide stream into the subsurface, where 

there is a pressure differential sufficient to cause movement of the carbon 

dioxide stream or formation fluids from the injection zone into a USDW. 

Rationale: Proposal removes words that are unnecessary to provide clarity and 

would only serve to confuse. 

Insert "from the injection zone" for clarification. 

Individual Response: EPA disagrees with the suggested edit. The final definition of pressure 

front at §146.81(d) is unchanged and reads as follows: “[T]he zone of elevated pressure that is 

47
created by the injection of carbon dioxide into the subsurface. For the purposes of this subpart, 

the pressure front of a carbon dioxide plume refers to a zone where there is a pressure differential 

sufficient to cause the movement of injected fluids or formation fluids into a USDW.” 

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0259 Comment ID: 24866 Letter Lines: 1113 to 1124 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment: EPA Proposal: Site closure the point/time, as determined by the Director 

following the requirements under § 146.93, at which the owner or operator of a 

GS site is released from post-injection site care responsibilities. 

GWPC Recommendations: Site closure means the point/time, as determined by the 

Director following the requirements under §146.93, at which the owner or 

operator of a GS project is released from post-injection site care 

responsibilities. 

Rationale: Add "means" 

Suggest using "GS project" to be consistent with other definitions 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

rule and NODA and Request for Comment, EPA has made many revisions to the GS Rule. See 

the final rule and preamble for further discussion on EPA's final approach. 

Letter ID: 0259 Comment ID: 24867 Letter Lines: 1126 to 1136 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment: EPA Proposal: Transmissive fault or fracture means a fault or fracture that has 

sufficient permeability and vertical extent to allow fluids to move between 

formations. 

GWPC Recommendations: Transmissive fault or fracture means a fault or fracture 

that has sufficient permeability and vertical extent to allow fluids to move 

beyond the confining zone. 

Rationale: Recommends changing "between formations" to "beyond the confining 

zone." The term between formations is insufficient as it could also include 

48
multiple zones within a injection zone. 

Individual Response: EPA has retained the proposed definition, which is the same as the 

existing definition at §148.2, to address transmissive faults and fractures that extend beyond the 

confining zone. 

Letter ID: 0259 Comment ID: 24868 Letter Lines: 1138 to 1157 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment: Rule Provision: 146.82 

EPA Proposal: Required Class VI permit information 

This section sets forth the information which the owner or operator must submit 

to the Director in order to be permitted as a Class VI well. The application 

for a permit for construction and operation of a Class VI well must include the 

following: 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Rule Provision: 146.82(a) 

EPA Proposal: (a) Information required in 40 CFR 144.31(e)(1) through (6); 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. For additional information on EPA's 

final regulatory approach, please see the final rule and preamble as well as the rulemaking 

docket. 

Letter ID: 0259 Comment ID: 24869 Letter Lines: 1159 to 1184 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: EPA Proposal: (b) A map showing the injection well(s) for which a permit is 

sought and the applicable area of review. Within the area of review, the map 

49
must show the number, or name and location of all injection wells, producing 

wells, abandoned wells, plugged wells or dry holes, deep stratigraphic 

boreholes, State or EPA approved subsurface cleanup sites, surface bodies of 

water, springs, mines (surface and subsurface), quarries, water wells and other 

pertinent surface features including structures intended for human occupancy and 

roads. [Highlighted text: The map should also show faults, if known or 

suspected.] Only information of public record is required to be included on this 

map; 

GWPC Recommendations: (b) A surface map showing the proposed locations for the 

injection well(s) for which a permit is sought and the applicable area of 

review. Within the area of review, the map must show the number, or name and 

location of all known injection wells, producing wells, abandoned wells, plugged 

wells or dry holes, deep stratigraphic boreholes, State or EPA approved 

subsurface cleanup sites, surface bodies of water, springs, mines (surface and 

subsurface), quarries, water wells and other pertinent surface features 

including structures intended for human occupancy and roads. Only information of 

public record is required to be included on this map; 

Rationale: Insert "known" before "injection" 

Suggests removing highlighted text as faults are not shown on maps unless there 

is a surface expression of the fault. Also, faults are detailed in (d) below 

and this language appears redundant. 

Individual Response: Regarding the comment that EPA delete mention of faults on surface 

maps, EPA believes that if faults have surface expressions, they should be presented on maps 

submitted; this information would complement the required cross section data. EPA is 

developing guidance on site characterization for GS projects to assist owners or operators and 

Directors in evaluating permit requirements and applications under §146.82. The guidance 

provides recommendations regarding characterizing the regional geology and hydrogeology of a 

proposed GS site as well as performing the necessary geochemical, geomechanical, and 

geophysical analyses of the injection and confining zone. The guidance can be found on EPA’s 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. Please see the 

final rule and the discussion of geologic site characterization in the preamble for additional 

information. 

EPA acknowledges but did not make the suggested edits. EPA believes that all of the site 

characterization requirements at §146.82, including geomechanical information and geologic and 

topographic maps and cross sections, are essential to proper siting of a GS well and are the 

foundation for a detailed understanding of the local and regional geology, and that the owner or 

operator should collect this information, regardless of whether it is known in advance of the 

siting process. Collecting and evaluating this data supports important evaluations regarding the 

suitability of the site to receive and contain injected CO2. 

EPA acknowledges that some smaller fractures may not be detectable during the site 

50
characterization process, and clarifies that §146.82(a)(3)(ii) requires the owner or operator to 

submit data on known or suspected faults and fractures (i.e., not all fractures). Other 

requirements for GS injection wells and sites can mitigate the potential impacts of unidentified 

fractures. These include limitations on injection pressures to avoid propagation of existing 

fractures in the confining zone (§146.88(a)), collection and assessments of CO2 monitoring data 

at the site, and AoR reevaluations (§146.84(e)) to assess possible CO2 movement through highpermeability regions (i.e., faults and/or fractures) not detected in the initial site characterization. 

Letter ID: 0259 Comment ID: 24870 Letter Lines: 1186 to 1197 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: EPA Proposal: (c) The area of review based on modeling, using data obtained 

during logging and testing of the well and the formation as required by 

paragraphs (l), (r), and (s) of this section; 

GWPC Recommendations: (c) A map delineating the area of review based upon 

modeling, using all available data including data available from any logging and 

testing of wells within the area of review. 

Rationale: Is this supposed to be a map, a tabular display, a cross section or 

series of cross sections etc... This appears to be related to a condition where 

a well is already drilled. This does not align with requesting information to 

receive a permit. 

Individual Response: EPA recognizes that information necessary for an area of review may not 

be available until after a well has been drilled and formation testing can occur. EPA revised 

§146.82 so that the final regulation specifies separate requirements for information to be 

submitted with the permit application and before well construction is approved (at §146.82(a)) 

and information to be submitted before operation of the well is authorized (at §146.82(c)) 

including The final area of review based on modeling, using data obtained during logging and 

testing of the well and the formation §146.82(c)(1). 

Based on its evaluation of all public comments and input on the proposed rule and NODA and 

Response to Comments EPA has made many revisions to the GS Rule. See the final rule and the 

site characterization discussion in the preamble for further discussion on EPA's final approach. 

Letter ID: 0259 Comment ID: 24871 Letter Lines: 1199 to 1223 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

51
Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: EPA Proposal: (d) Information on the geologic structure and hydrogeologic 

properties of the proposed storage site and overlying formations, including: 

(1) Maps and cross sections of the area of review; 

(2) Location, orientation, and properties of known or suspected faults and 

fractures that may transect the confining zone(s) in the area of review and a 

determination that they would not interfere with containment; 

GWPC Recommendations: (d) Sufficient information on the geologic structure and 

reservoir properties of the proposed storage site and overlying formations, 

including: 

(1) Isopach maps of the proposed injection and confining zone(s), a structural 

contour map aligned with the top of the proposed injection zone, and at least 

two geologic cross sections of the area of review reasonably perpendicular to 

each other showing the geologic formations from the surface to total depth. 

(2) Location, orientation, and properties of known or suspected subsurface 

faults that may transect the confining zone(s) in the area of review and a 

determination that they would not interfere with containment; 

Rationale: Fractures can be incredibly small and it is virtually impossible to 

find all subsurface fractures. The GWPC also recommends addition of the term 

"Sufficient" before the information sought in (d) as this is more precise. 

Individual Response: EPA acknowledges that some smaller fractures may not be detectable 

during the site characterization process, and clarifies that §146.82(a)(3)(ii) requires the owner or 

operator to submit data on known or suspected faults and fractures (i.e., not all fractures). Other 

requirements for GS injection wells and sites can mitigate the potential impacts of unidentified 

fractures. These include limitations on injection pressures to avoid propagation of existing 

fractures in the confining zone (§146.88(a)), collection and assessments of CO2 monitoring data 

at the site, and AoR reevaluations (§146.84(e)) to assess possible CO2 movement through highpermeability regions (i.e., faults and/or fractures) not detected in the initial site characterization. 

EPA disagrees with the other suggested edits because the GS rule, as written, affords flexibility 

to owners or operators and Directors to tailor the site characterization process to the unique 

features of the site. Please see the final rule and the discussion of geologic site characterization in 

the preamble for additional information. 

52
Letter ID: 0259 Comment ID: 24872 Letter Lines: 1225 to 1258 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: EPA Proposal: (3) Information on seismic history including the presence and 

depth of seismic sources and a determination that the seismicity would not 

interfere with containment; 

(4) Data on the depth, areal extent, thickness, mineralogy, porosity, 

permeability and capillary pressure of the injection and confining zone(s); 

including geology/facies changes based on field data which may include geologic 

cores, outcrop data, seismic surveys, well logs, and names and lithologic 

descriptions; 

(5) Geomechanical information on fractures, stress, ductility, rock strength, 

and in situ fluid pressures within the confining zone; and 

GWPC Recommendations: (3) Information on seismic history that have affected the 

proposed area of review including knowledge of previous seismic events and 

history of these events, including the presence and depth of seismic sources and 

a determination that the seismicity would not compromise containment; 

(4) Data sufficient to demonstrate the effectiveness of the injection and 

confining zone(s), including data on the depth, areal extent, thickness, 

mineralogy, porosity, vertical permeability reservoir pressure and of the 

injection and confining zone(s) within the area of review; including geologic 

changes based on field data which may include geologic cores, outcrop data, 

seismic surveys, well logs, capillary pressure tests and names and lithologic 

descriptions; 

(5) Geomechanical information on the confining zone(s) within the area of 

review; and 

Rationale: Capillary pressure is too hard to measure outside the lab; how 

comparable are lab results to what goes into the ground. Sidewall core may not 

be sufficient to do this, and it is difficult to core the whole of the confining 

and injection zones. Rewording keeps the usefulness of capillary pressure in the 

provision without making it a mandatory use. 

Individual Response: EPA acknowledges that laboratory methods are standard for determining 

capillary pressures regardless of formation permeability and that in situ measurements would 

require drilling of a well. However, EPA also anticipates that test wells will be drilled to support 

53
geologic site characterization of the proposed GS sites and can be used to collect subsurface 

samples (for laboratory determination of capillary pressure) and take other necessary 

measurements. EPA believes that information on capillary entry pressure is necessary and 

appropriate. Capillary entry pressure measurements on core samples can quantify the amount of 

buoyant force the confining zone can maintain before failure (World Resources Institute, 2008). 

EPA recognizes that this information may not be available until after a well has been drilled. 

EPA revised §146.82 so that the final regulation specifies separate requirements for information 

to be submitted with the permit application and before well construction is approved (at 

§146.82(a)) and information to be submitted before operation of the well is authorized (at 

§146.82(c)). Final information on injection zone pressures would be required following drilling 

of the well, at §146.82(c)(4). 

Letter ID: 0259 Comment ID: 24873 Letter Lines: 1260 to 1263 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: EPA Proposal: (6) Geologic and topographic maps and cross sections illustrating 

regional geology, hydrogeology, and the geologic structure of the local area. 

GWPC Recommendations: Support the EPA language. 

Individual Response: EPA acknowledges the comment and the final rule retains the text as 

proposed. 

Letter ID: 0259 Comment ID: 24874 Letter Lines: 1265 to 1281 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(e) 

EPA Proposal: (e) A tabulation of all wells within the area of review which 

penetrate the injection or confining zone(s). Such data must include a 

description of each well’s type, construction, date drilled, location, depth, 

record of plugging and/ or completion, and any additional information the 

Director may require; 

GWPC Recommendations: (e) A compilation of all artificial penetrations within 

54
the area of review which penetrate the injection or confining zone(s). Such data 

must include a description of each well’s type, construction, date drilled, 

location, depth, record of plugging and/ or completion, and any additional 

information the Director may require; 

Rationale: The GWPC felt that the term compilation was more appropriate than 

tabulation because tabulation as tabulation implies a spreadsheet while 

compilation can take numerous forms. 

Individual Response: EPA used the term tabulation in the final rule because it is the same term 

used in the same requirement for other well classes; and, the regulated community and 

permitting officials are familiar with existing terminology. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and 

Response to Comments EPA has made many revisions to the GS Rule. See the final rule and 

preamble for further discussion on EPA's final approach. 

Letter ID: 0259 Comment ID: 24875 Letter Lines: 1283 to 1295 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: EPA Proposal: (f) Maps and stratigraphic cross sections indicating the general 

vertical and lateral limits of all USDWs, water wells and springs within the 

area of review, their positions relative to the injection zone(s) and the 

direction of water movement, where known; 

GWPC Recommendations: (f) Maps and stratigraphic cross sections indicating the 

general vertical and lateral limits of all USDWs, the location of water wells 

and perennial springs within the area of review, their positions relative to the 

injection zone(s) and the direction of water movement, where known; 

Rationale: Clarification: Use of the term perennial before springs will prevent 

a requirement to list very minor, intermittent springs which are not 

hydrologically significant. 

Individual Response: EPA acknowledges the comment; however, the final rule does not reflect 

the suggested edit. The Agency uses the term “springs” in the site characterization requirements 

for other classes of wells (see §146.70 (a)(2)) and the term is familiar to the regulated 

community and permitting officials. EPA adds that characterization will be site-specific, and 

owners or operators are encouraged to discuss the site with the Director as data are collected to 

identify thresholds for certain types of data. 

55
Based on its evaluation of all public comments and input on the proposed rule and NODA and 

Response to Comments EPA has made many revisions to the GS Rule. See the final rule and 

preamble for further discussion on EPA's final approach. 

Letter ID: 0259 Comment ID: 24876 Letter Lines: 1297 to 1307 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: EPA Proposal: (g) Baseline geochemical data on subsurface formations, including 

all USDWs in the area of review; 

GWPC Recommendations: (g) Compilation of available baseline geochemical data on 

the proposed injection zone and nearest adjacent porous and permeable formation 

to the confining zone, existing utilized water supply aquifers and any other 

USDWs designated by the Director. 

Rationale: It will be unduly burdensome to address "all USDWs" in some contexts. 

This revision allows for more appropriate focusing on those USDWs designated by 

the Director. 

Individual Response: EPA believes that identifying and mapping all surrounding USDWs near 

an injection well, as specified at §146.82(a)(5), is necessary to ensure protection of all USDWs 

from endangerment. The purpose of the UIC requirements (including those for Class VI wells) is 

to ensure the protection of USDWs from endangerment, which are defined based on total 

dissolved solids (TDS) content, not their location or depth (40 CFR §144.3). 

EPA adds that knowing the number, location and depth of USDWs near an injection well will 

generate baseline regional information, support development of an effective testing and 

monitoring plan, and enhance owner or operator and Director understanding of the site. This 

requirement is common to all injection well classes. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and 

Response to Comments EPA has made many revisions to the GS Rule. See the final rule and 

preamble for further discussion on EPA's final approach. 

Letter ID: 0259 Comment ID: 24877 Letter Lines: 1309 to 1430 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82) 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

56
comment) 

Comment: EPA Proposal: (h) Proposed operating data: 

(1) Average and maximum daily rate and volume of the carbon dioxide stream; 

(2) Average and maximum injection pressure; 

(3) The source of the carbon dioxide stream; and 

(4) An analysis of the chemical and physical characteristics of the carbon 

dioxide stream; 

GWPC Recommendations: (h) Proposed operating data: 

(1) Average and maximum daily injection rate and volume of the carbon dioxide 

stream; 

(2) Average and maximum surface injection pressure; 

(3) The source of the carbon dioxide stream; and 

(4) An analysis of the chemical and physical characteristics of the carbon 

dioxide stream; 

Rationale: Clarification: Addition of the term surface in (h)(d) will make it 

clear as to where the injection pressure is to measured. 

Rule Provision: 146.82(i) 

EPA Proposal: (i) The compatibility of the carbon dioxide stream with fluids in 

the injection zone and minerals in both the injection and the confining zone(s), 

based on the results of the formation testing program, and with the materials 

used to construct the well; 

(j) Proposed formation testing program to obtain an analysis of the chemical and 

physical characteristics of the injection zone and confining zone; 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

EPA Proposal: (k) Proposed stimulation program and a determination that 

stimulation will not interfere with containment; 

(l) The results of the formation testing program as required in paragraph (j) of 

this section; 

(m) Proposed procedure to outline steps necessary to conduct injection operation; 

(n) Schematic or other appropriate drawings of the surface and subsurface 

construction details of the well; 

57
(o) Injection well construction procedures that meet the requirements of § 

146.86; 

GWPC Recommendations: (k) Proposed stimulation program and a determination that 

stimulation will not compromise containment; 

(l) The results of the formation testing program as required in paragraph (j) of 

this section; 

(m) Proposed procedure to outline steps necessary to conduct injection 

operation; 

(n) A wellbore schematic of the subsurface construction details and surface 

wellhead construction. 

(o) Injection well construction procedures that meet the requirements of § 

146.86; 

Rationale: "Interfere" is too ambiguous and should be replaced by "compromise" 

which limits concerns to situations where containment may be lost. 

EPA Proposal: (p) Proposed area of review and corrective action plan that meets 

the requirements under § 146.84; 

(q) The status of corrective action on wells in the area of review; 

(r) All available logging and testing program data on the well required by § 

146.87; 

(s) A demonstration of mechanical integrity pursuant to § 146.89; 

(t) A demonstration, satisfactory to the Director, that the applicant has met 

the financial responsibility requirements under § 146.85; 

GWPC Recommendations: (p) Proposed corrective action plan for artificial 

penetrations within the area of review, if necessary 

(q) All available logging and testing program data on the well required by § 

146.87; 

(r) The proposed demonstration method for mechanical integrity pursuant to 

(s) A demonstration, satisfactory to the Director, that the applicant has met 

the financial responsibility requirements under § 146.85; 

58
Rationale: (q) Should be deleted because it is not part of an application 

process but, rather a post permitting activity. This would result in a renumbering of the subsections after the new (q). 

Rule Provision: 146.82(u) 

EPA Proposal: (u) Proposed testing and monitoring plan required by § 146.90; 

(v) Proposed injection well plugging plan required by § 146.92(b); 

(w) Proposed post-injection site care and site closure plan required by § 

146.93(a); 

(x) Proposed emergency and remedial response plan required by § 146.94; and 

(y) Any other information requested by the Director. 

GWPC Recommendations: (t) Proposed testing and monitoring plan required by § 

146.90; 

(u) Proposed injection and monitoring well(s) plugging plan required by § 

146.92(b); 

(v) Proposed post-injection site care and site closure plan required by § 

146.93(a); 

(w) Proposed emergency and remedial response plan required by § 146.94; and 

(x) Any other information requested by the Director. 

Rationale: Need to address the plugging of monitoring well(s), if any, included 

in the project. 

Individual Response: EPA acknowledges the commenter’s support for portions of the subject 

requirements. EPA disagrees that the technical clarifications suggested are necessary. EPA adds 

that it is developing guidance for owners or operators on the geologic site characterization and 

AoR and corrective action processes. These guidances will provide recommendations and clarify 

the intent of all required elements of a permit application. The guidances can be found on EPA’s 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24878 Letter Lines: 1432 to 1446 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment: Rule Provision: 146.83 

59
EPA Proposal: Minimum criteria for siting 

(a) Owners or operators of Class VI wells must demonstrate to the satisfaction 

of the Director that the wells will be sited in areas with a suitable geologic 

system. The geologic system must be comprised of: 

(1) An injection zone of sufficient areal extent, thickness, porosity, and 

permeability to receive the total anticipated volume of the carbon dioxide 

stream; 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment and the final rule retains the text at 

§146.83(a) as proposed. 

Letter ID: 0259 Comment ID: 24879 Letter Lines: 1448 to 1460 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3110 2.1.1 Proposed siting requirements (i.e., injection/confining zones, 

trapping mechanism) 

Comment: EPA Proposal: (2) A confining zone(s) that is free of transmissive faults or 

fractures and of sufficient areal extent and integrity to contain the injected 

carbon dioxide stream and displaced formation fluids and allow injection at 

proposed maximum pressures and volumes without initiating or propagating 

fractures in the confining zone(s); and 

GWPC Recommendations: (2) A confining zone(s) that is laterally continuous and 

free of known transecting, transmissive faults or fractures over an area 

sufficient to prevent the movement of fluids into a USDW; 

Rationale: Suggest using the Class I regulation for this paragraph (2) in 

146.62(c) with the addition of reactivation of existing faults or fractures and 

before the terms faults or fractures the word known should be added. 

Individual Response: The Agency believes that the requirement at §146.83(a)(2) that the 

confining zone to be free of transmissive faults or fractures is appropriate for Class VI wells and 

is necessary to ensure containment of the injectate and that requiring the confining zone to be 

free of transmissive faults maximizes protection of USDWs from endangerment. EPA believes 

that the text regarding propagation of faults and fractures is important to avoid the potential for 

fluid movement and to ensure that injection is at appropriate pressures. Class I hazardous waste 

injection well operators must also meet a similar requirement that the site is free of transmissive 

faults or fractures; they have successfully made such demonstrations in the past. While core 

60
samples obtained through drilling and hydraulic testing are direct methods to obtain such 

information, geophysical techniques such as seismic or electromagnetic surveys can also be used 

in many geologic settings to demonstrate the absence of or identify and characterize the presence 

of faults or fractures. EPA adds that the Director will evaluate all geologic data on the site to 

ensure protection of USDWs from endangerment before approving a site for a GS project. 

Letter ID: 0259 Comment ID: 24880 Letter Lines: 1462 to 1471 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones 

(seeking comment) 

Comment: EPA Proposal: (b) At the Director’s discretion, owners or operators of Class VI 

wells must identify and characterize additional zones that will impede vertical 

fluid movement, are free of faults and fractures that may interfere with 

containment, allow for pressure dissipation, and provide additional 

opportunities for monitoring, mitigation and remediation. 

GWPC Recommendations: Delete paragraph 

Rationale: This paragraph creates a presumption that additional zones WILL be 

required. It is also redundant from previous sections. 

Individual Response: EPA clarifies that secondary confining zones are not required for all GS 

sites. Rather, secondary confining zones are required when the Director determines that these 

zones are needed to maximize the protection of USDWs from endangerment. EPA retains the 

requirement to identify additional containment/confining zones, if required by the Director, as 

proposed (e.g., §146.83(b)). EPA believes that, in some situations, the presence of additional 

confining and containment zones above the primary (i.e., lowermost) confining zone can 

improve USDW protection. These layers could further impede vertical fluid movement and 

allow for pressure dissipation, and also provide additional sites for monitoring, mitigation, and 

remediation. 

Letter ID: 0259 Comment ID: 24881 Letter Lines: 1473 to 1489 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

Comment: Rule Provision: 146.84 

EPA Proposal: 146.84. Area of review and corrective action 

(a) The area of review is the region surrounding the geologic sequestration 

project that may be impacted by the injection activity. The area of review is 

based on computational modeling that accounts for the physical and chemical 

61
properties of all phases of the injected carbon dioxide stream. 

GWPC Recommendations: (a) The area of review is based on computational modeling 

that accounts for the physical and chemical properties of all phases of the 

injected carbon dioxide stream. 

Rationale: This is the same as the definition of "Area of review" that was 

revised by the GWPC .to delete the first sentence. 

Comments on many provisions are predicated on proposed changes in definitions 

Individual Response: The Agency has carefully considered all comments on the AoR definition 

at 146.84(a) and modified it to read as follows: The region surrounding the geologic 

sequestration project where USDWs may be endangered by the injection activity. The area of 

review is delineated using computational modeling that accounts for the physical and chemical 

properties of all phases of the injected CO2 stream and is based on available site 

characterization, monitoring, and operational data. 

Letter ID: 0259 Comment ID: 24882 Letter Lines: 1491 to 1521 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action 

plan 

Comment: EPA Proposal: (b) The owner or operator of a Class VI well must prepare, 

maintain, and comply with a plan to delineate the area of review for a proposed 

geologic sequestration project, periodically reevaluate the delineation, and 

perform corrective action that meets the requirements of this section and is 

acceptable to the Director. As a part of the permit application for approval by 

the Director, the owner or operator must submit an area of review and corrective 

action plan that includes the following information: 

(1) The method for delineating the area of review that meets the requirements of 

paragraph (c) of this section, including the model to be used, assumptions that 

will be made, and the site characterization data on which the model will be 

based; 

GWPC Recommendations: (b) The owner or operator of a Class VI well must prepare, 

maintain, and comply with a plan to delineate the area of review for a proposed 

geologic sequestration project, reevaluate the delineation, and perform 

corrective action that meets the requirements of this section in a manner and at 

a frequency acceptable to the Director. As a part of the permit application, the 

owner or operator must submit an area of review and corrective action plan that 

includes the following information: 

Rationale: Suggest deletion of "periodically." See Workgroup recommendation 7.6 

62
from 

Recommendations for the Regulatory Management of Geologic Sequestration of CO2 

Under the UIC Program 

Replace with "in a manner and at a frequency" 

Delete "for approval by the Director,". Director’s approval is implicit in a 

permit application. 

Individual Response: EPA disagrees with the suggested change, and is retaining the approach 

of setting a minimum fixed frequency for reevaluating the AoR but has, based on commenters' 

input, changed the frequency from 10 years to at least every 5 years, as specified in §146.84(e). 

EPA agrees with commenters that site-specific information is an important factor in determining 

an appropriate AoR reevaluation frequency, and adds that the owner or operator's AoR and 

corrective action plan must describe the minimum fixed frequency for reevaluating the AoR and 

the site-specific conditions on which this frequency is based. EPA adds that the Director will 

evaluate the proposed plan in connection with a review of a vast amount of geologic and 

proposed operating data in determining whether to approve the plan. EPA is developing guidance 

describing approaches to preparing all of the required GS project plans, which will address 

considerations for determining an appropriate AoR reevaluation schedule. The guidance will be 

available on EPA's web site, at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24883 Letter Lines: 1523 to 1542 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3500 2.2.3 Area of Review Reevaluation (seeking comment) 

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action 

plan 

Comment: Rule Provision: 146.84(b)(2) 

EPA Proposal: (2) A description of: 

(i) The minimum fixed frequency, not to exceed 10 years, the owner or operator 

proposes to reevaluate the area of review; 

(ii) The monitoring and operational conditions that would warrant a reevaluation 

of the area of review prior to the next scheduled reevaluation as determined by 

the minimum fixed frequency established in paragraph (b)(2)(i) of this section. 

(iii) How monitoring and operational data (e.g., injection rate and pressure) 

will be used to inform an area of review reevaluation; and 

GWPC Recommendations: Delete (i) and (ii) 

63
Rationale: Suggest deletion of (i) as this is handled by "manner and at a 

frequency acceptable to the Director in (b) 

Suggest deletion of (ii) for same reason as comment on (i) 

Individual Response: EPA believes that periodic AoR reevaluation at a set frequency of at least 

every 5 years is necessary to ensure protection of USDWs from endangerment and address the 

uncertainties inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure 

that a deliberate effort is made to verify, based on monitoring and operational data, that the CO2 

plume is moving within the subsurface as predicted. EPA believes that less frequent 

reevaluations may not be sufficient to appropriately model plume and pressure front movement, 

establish conditions for corrective action, and ensure protection of USDWs from endangerment. 

EPA clarifies that if site monitoring data agrees with the existing AoR delineation, a model 

recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration 

that the current AoR delineation is adequate based on site monitoring data. 

Letter ID: 0259 Comment ID: 24884 Letter Lines: 1544 to 1564 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3400 2.2.2 Corrective Action 

Comment: EPA Proposal: (iv) How corrective action will be conducted to meet the 

requirements of paragraph (d) of this section, including what corrective action 

will be performed prior to injection and what, if any, portions of the area of 

review will have corrective action addressed on a phased basis and how the 

phasing will be determined; how corrective action will be adjusted if there are 

changes in the area of review; and how site access will be guaranteed for future 

corrective action. 

GWPC Recommendations: (iv) How corrective action will be conducted to meet the 

requirements of paragraph (d) of this section, including what corrective action 

will be performed prior to injection and what, if any, portions of the area of 

review will have corrective action addressed on a phased basis and how the 

phasing will be determined; how corrective action will be adjusted if there are 

changes in the area of review; and how site access will be assured for future 

corrective action. 

Rationale: Replace "guaranteed" with "assured" Future access cannot be 

absolutely guaranteed for an area in advance that may not even be within the 

boundaries of the AOR/ project. However, assurance of access is a standard that 

is less onerous than guaranteed, it is firmer than another standard such as 

"arranged" 

64
Individual Response: EPA is retaining this requirement as proposed. The purpose of the 

corrective action requirement at §146.84(d) is to ensure that all wells in the AoR that have the 

potential to cause the movement of CO2 or other fluids into or between USDWs receive 

appropriate corrective action. In general, to meet this requirement, the owner or operator will 

most likely need to obtain the right of access to wells that may require corrective action, and 

demonstrate they have done this in their proposed AoR and corrective action plan. In the AoR 

and corrective action plan, the owner or operator must describe how site access will be 

guaranteed for future corrective action, as specified in §146.84(b)(2)(iv). 

Letter ID: 0259 Comment ID: 24885 Letter Lines: 1566 to 1590 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

Comment: Rule Provision: 146.84(c) 

(c) Owners or operators of Class VI wells must perform the following actions to 

delineate the area of review, identify all wells that require corrective action, 

and perform corrective action on those wells: 

(1) Predict, using computational modeling, the projected lateral and vertical 

migration of the carbon dioxide plume and formation fluids in the subsurface 

from the commencement of injection activities until the plume movement ceases, 

pressure differentials sufficient to cause the movement of injected fluids or 

formation fluids into a USDW are no longer present, or after a fixed time period 

as determined by the Director. The model must: 

GWPC Recommendations: (c) Owners or operators of Class VI wells must perform the 

following actions to delineate the area of review, identify all wells that 

require corrective action, and perform corrective action on those wells: 

(1) Predict, using computational modeling, the projected lateral and vertical 

migration of the carbon dioxide plume and formation fluids in the subsurface 

from the commencement of injection activities until the plume movement ceases, 

pressure differentials sufficient to cause the movement of injected fluids or 

formation fluids into a USDW are no longer present, or for a fixed time period 

as determined by the Director. The model must: 

Rationale: Should say "for" not "after." 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

rule, EPA has clarified this language in the final rule. It now reads, “Predict, using existing site 

characterization, monitoring and operational data, and computational modeling, the projected 

lateral and vertical migration of the carbon dioxide plume and formation fluids in the subsurface 

from the commencement of injection activities until the plume movement ceases, until pressure 

65
differentials sufficient to cause the movement of injected fluids or formation fluids into a USDW 

are no longer present, or until the end of a fixed time period as determined by the Director.” 

Letter ID: 0259 Comment ID: 24886 Letter Lines: 1592 to 1628 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

Comment: Rule Provision: 146.84(c)(i) 

EPA Proposal: (i) Be based on detailed geologic data collected to characterize 

the injection zone, confining zone and any additional zones; and anticipated 

operating data, including injection pressures, rates and total volumes over the 

proposed life of the geological sequestration project; 

(ii) Take into account any geologic heterogeneities, data quality, and their 

possible impact on model predictions; and 

(iii) Consider potential migration through faults, fractures, and artificial 

penetrations. 

GWPC Recommendations: (i) Be based on detailed geologic data collected to 

characterize the injection zone, confining zone; and anticipated operating data, 

including injection pressures, rates and total volumes over the duration of 

injection; 

(ii) Take into account relevant geologic heterogeneities, and data quality, and 

their possible impact on model predictions; and 

(iii) Consider potential migration through faults, fractures, and artificial 

penetrations. 

Rationale: Suggest deletion of "any additional zones". You do not need to 

include any additional zones if you use the current CFR definition of confining 

zone since it includes multiple zones. 

Should be geologic not geological for consistency with other provisions because 

geologic sequestration project is defined. 

Suggest "duration of injection" instead of "life of the geological sequestration 

project" 

Suggest "relevant" instead of any in (ii) 

Insert "and" between "heterogeneities" and "data" 

66
Individual Response: EPA agrees that detailed geologic data is invaluable to modeling an 

accurate AoR. The Agency believes that the AoR delineation requirements in 146.84 (c)(1)(i), 

which specify using "detailed geologic data collected to characterize the injection zone, 

confining zone and any additional zones; and anticipated operating data...," and (c)(iii) to 

"consider potential migration through faults, fractures and artificial penetrations," provide the 

necessary information needed for appropriate site modeling, subsequent site evaluation, and 

protection of USDWs from endangerment. EPA adds that the extensive requirements for data 

that is to be included in the permit application at 146.82 incorporate these same types of 

information. The Director will review the AoR models in the context of the extensive site data 

submitted with the permit application. EPA recognizes that in some instances, the Director may 

require additional types of data to be included in the AoR delineation (146.84(c)(1)). Based on 

its evaluation of all public comments and input on the proposed rule and NODA and Request for 

Comment EPA has made many revisions to the GS Rule. See the final rule and preamble for 

further discussion on EPA's final approach. 

EPA disagrees that only the injection and confining zones should be included in AoR modeling 

of GS sites. EPA believes that the modeling should also take into account the possibility of 

displaced fluids or brines caused by a lateral and/or vertical pressure plume, and therefore it may 

be necessary to include additional zones along with the confining/injection zones to ensure the 

integrity of the confining zone and ultimately protect a USDW from endangerment. 

Letter ID: 0259 Comment ID: 24887 Letter Lines: 1630 to 1661 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3400 2.2.2 Corrective Action 

Comment: EPA Proposal: (2) Using methods approved by the Director, identify all 

penetrations, including active and abandoned wells and underground mines, in the 

area of review that may penetrate the confining zone. Provide a description of 

each well’s type, construction, date drilled, location, depth, record of 

plugging and/or completion, and any additional information the Director may 

require; and 

GWPC Recommendations: (2) Using methods approved by the Director, identify all 

known artificial penetrations into the confining zone, including active and 

abandoned wells and underground mines, in the area of review that may penetrate 

the confining zone. Provide a description of each well’s type, construction, 

date drilled, location, depth, record of plugging and/or completion, and any 

additional information the Director may require; and 

Rationale: Insert "known artificial penetrations into the confining zone" 

EPA Proposal: (3) Determine which abandoned wells in the area of review have 

been plugged (as required by § 146.92) in a manner that prevents the movement of 

carbon dioxide or associated fluids that may endanger USDWs 

67
GWPC Recommendations: (3) Determine which abandoned wells identified in 146.84 

(c) (2) have been plugged (as required by §146.92) in a manner that prevents the 

movement of carbon dioxide or displaced formation fluids that may endanger 

USDWs. 

Rationale: Add identified in 146.84 (c) (2) 

Remove "area of review" as redundant. 

Suggest change "associated fluids" to "displaced formation fluids." Associated 

fluids is not defined so if EPA means displaced formation fluids the regulation 

should just use this term. Otherwise, you need to define associated fluids. 

Individual Response: EPA is retaining the requirement in 146.84(c)(2) as proposed. EPA agrees 

with commenters that, for most GS sites, relying on database and other public records searches 

(i.e., of "known" artificial penetrations) will be sufficient to meet the requirements at 

§146.84(c)(2). However, the Agency recognizes that there may be situations where additional 

surveys or research to locate wells may be appropriate. For example, there may be cases where 

the Director may determine that ground or airborne surveys for wells are appropriate, e.g., if 

there is reason to believe, based on knowledge of the site or of available data, that the 

incompleteness of information on known wells could compromise USDW protection from 

endangerment. In order to preserve the Director's discretion to require an operator to supplement 

a records search, EPA did not make the suggested change. 

EPA clarifies that the term "associated fluids" as proposed in §146.84(c)(3) refers to formation 

fluids, other injectates, etc that may be present in the subsurface and affect movement of the CO2 

plume and/or pressure front. EPA believes this terminology would incorporate any fluids in the 

subsurface that could potentially move through artificial penetrations and affect USDWs. EPA 

has revised the language at §146.84(c)(3) to read, "... carbon dioxide or other fluids that may 

endanger USDWs..." 

Letter ID: 0259 Comment ID: 24888 Letter Lines: 1663 to 1678 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3460 2.2.2.3 Acceptable corrective action techniques for GS sites (e.g., 

cements) 

Comment: Rule Provision: 146.84(d) 

EPA Proposal: (d) Owners or operators of Class VI wells must perform corrective 

action on all wells in the area of review that are determined to need corrective 

action using methods necessary to prevent the movement of fluid into or between 

USDWs including use of corrosion resistant materials, where appropriate. 

68
GWPC Recommendations: (d) Owners or operators of Class VI wells must perform 

corrective action using materials suitable for use with carbon dioxide streams, 

on all wells identified in 146.84(c)(2) that are determined to need corrective 

action". 

Rationale: Re-write as follows "Owners or operators of Class VI wells must 

perform corrective action using corrosion resistant materials, when appropriate, 

on all wells identified in 146.84(c)(2) that are determined to need corrective 

action". 

Individual Response: EPA revised the text at §146.84(d) to require the use of materials that are 

"compatible with the carbon dioxide stream." EPA believes this language change addresses 

commenters' concerns and is also consistent with other language regarding materials 

requirements in the GS rule. 

Letter ID: 0259 Comment ID: 24889 Letter Lines: 1680 to 1687 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3400 2.2.2 Corrective Action 

Comment: EPA Proposal: (e) If monitoring data indicate an endangerment to USDWs, the 

owner or operator must notify the Director and cease operations as required by § 

146.94. 

GWPC Recommendations: Delete 

Rationale: Why is this needed if 146.94 already specifies the notification and 

cessation of injection? 

Individual Response: Based on consideration of all public comments and other information, 

EPA deleted this provision from §146.84. The final rule now contains a provision in §146.91(c) 

that requires the owner or operator to report within 24 hours any evidence that the carbon dioxide 

stream or associated pressure front may cause an endangerment to a USDW. EPA believes this 

change consolidates reporting requirements in one place and provides additional clarity. 

Letter ID: 0259 Comment ID: 24890 Letter Lines: 1689 to 1711 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3530 2.2.3.1 AoR reevaluation frequency (seeking comment) 

Comment: EPA Proposal: (f) At the minimum fixed frequency, not to exceed 10 years, as 

specified in the area of review and corrective action plan, or when monitoring 

and operational conditions warrant, owners or operators must: 

(1) Reevaluate the area of review in the same manner specified in paragraph (c) 

69
(1) of this section; 

(2) Identify all wells in the reevaluated area of review that require corrective 

action in the same manner specified in paragraph (c)(2) of this section; 

GWPC Recommendations: (f) As specified in the approved area of review and 

corrective action plan, or when monitoring and operational conditions warrant, 

owners or operators must 

(1) Reevaluate the area of review in the same manner specified in paragraph (c) 

(1) of this section; 

(2) Identify all wells in the reevaluated area of review that require corrective 

action in the same manner specified in paragraph (c)(2) of this section; 

Rationale: Delete "At the minimum fixed frequency, not to exceed 10 years". 

Insert "approved" before "area of review" in (f). 

Individual Response: EPA disagrees with the suggested edit, and believes that periodic AoR 

reevaluation at a set frequency is necessary to ensure protection of USDWs from endangerment 

and address the uncertainties inherent in predictive modeling. Periodic AoR reevaluations at 

§146.84(e) ensure that a deliberate effort is made to verify, based on monitoring and operational 

data, that the CO2 plume is moving within the subsurface as predicted. EPA believes that less 

frequent reevaluations may not be sufficient to appropriately model plume and pressure front 

movement, establish conditions for corrective action, and ensure protection of USDWs from 

endangerment. 

EPA clarifies that if site monitoring data agrees with the existing AoR delineation, a model 

recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration 

that the current AoR delineation is adequate based on site monitoring data. 

Letter ID: 0259 Comment ID: 24891 Letter Lines: 1713 to 1731 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action 

plan 

Comment: EPA Proposal:(3) Perform corrective action on wells requiring corrective action 

in the reevaluated area of review in the same manner specified in paragraph (c) 

(3) of this section; and 

(4) Submit an amended area of review and corrective action plan or demonstrate 

to the Director through monitoring data and modeling results that no amendment 

to the area of review and corrective action plan is needed. 

70
GWPC Recommendations: (3) Perform corrective action on wells requiring 

corrective action in the reevaluated area of review in the same manner specified 

in paragraph (c)(3) of this section; and 

(4) Submit an amended area of review and corrective action plan or demonstrate 

to the Director through monitoring data and modeling results that no change to 

the area of review and corrective action plan is needed. 

Rationale: Suggest "change" instead of "amendment" in (4) because the term 

amendment is typically construed to mean an official permit modification 

process. 

Individual Response: EPA disagrees with the suggested change regarding the term 

“amendment.” EPA believes that, in some cases an amendment to the AoR and corrective action 

plan may warrant a permit modification. EPA added text to §144.39(a)(5) that permit 

modifications, requiring public notice and comment, are required if the Director determines that 

a modification is necessary based on an AoR reevaluation, amendments to any of the project 

plans, or a review of the testing and monitoring results. EPA made this change because the 

Agency recognizes that the AoR reevaluation process and any subsequent modifications to the 

plans may generate significant levels of public interest. 

EPA clarifies that if site monitoring data agrees with the existing AoR delineation, a model 

recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration 

that the current AoR delineation is adequate based on site monitoring data. 

Letter ID: 0259 Comment ID: 24892 Letter Lines: 1733 to 1747 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

Comment: Rule Provision: 146.84(g) 

(g) The emergency and remedial response plan (as required by § 146.94) and a 

demonstration of financial responsibility (as described by § 146.85) must 

account for the entire area of review, regardless of whether or not corrective 

action in the area of review is phased. 

GWPC Recommendations: (g) The emergency and remedial response plan (as required 

by § 146.94) and a demonstration of financial responsibility (as described by § 

146.85) must account for the entire area of review [as modified], regardless of 

whether or not corrective action in the area of review is phased. 

Rationale: Need to add phrase to account for the periodic reevaluations and 

possible revisions that will be occurring. Addition of the term [as modified] 

71
addresses this concern. 

Individual Response: EPA agrees with the commenter and has modified the final rule at 

§146.84(f) to require the owner or operator to periodically review the emergency and remedial 

response plan to take into account the most recent AoR. Owners or operators must also 

periodically update the demonstration of financial responsibility to account for any such changes. 

Letter ID: 0259 Comment ID: 24893 Letter Lines: 1749 to 1771 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: Rule Provision: 146.85 

EPA Proposal: 146.85 Financial responsibility 

(a) The owner or operator must demonstrate and maintain financial responsibility 

and resources for corrective action (that meets the requirements of § 146.84), 

injection well plugging (that meets the requirements of § 146.92), postinjection site care and site closure (that meets the requirements of § 146.93), 

and emergency and remedial response (that meets the requirements of§ 146.94) in 

a manner prescribed by the Director until: 

(1) The Director receives and approves the completed post-injection site care 

and site closure plan; and 

(2) The Director determines that the site has reached the end of the postinjection site care period. 

GWPC Recommendations: No specific language recommended. See rationale 

Rationale: Maintenance of plugging liability until site closure release by the 

Director is probably not needed once the well has been plugged. Should the 

owner/ operator be allowed to make a demonstration to the Director for the 

partial release of other financial responsibility elements? 

Individual Response: EPA will allow owners or operators to use separate or multiple financial 

responsibility instruments for different GS activities. However, owners or operators must 

demonstrate adequate financial responsibility for all required activities, including well plugging, 

with their permit application, per §146.82(a)(14). In addition, on an annual basis, the owner or 

operator must adjust the cost estimate for inflation, increase or decrease the value of the financial 

instrument to match the cost estimate, and provide any updated information related to their 

financial responsibility instrument(s), or at any other time deemed appropriate by the Director. 

These annual reviews provide a mechanism for revising cost estimates up or down to account for 

changes in the project, including the execution of environmental obligations as phases of a GS 

72
project are completed. See the final rule and preamble for further discussion of EPA's final 

approach to financial responsibility. 

Regarding the suggested edit at §146.85(a)(1), EPA clarifies that the owner or operator may be 

released from a financial instrument when the phase of the project for which the instrument was 

required is complete and financial obligations for the required activity have been met, as 

specified in §146.85(b)(2). 

Letter ID: 0259 Comment ID: 24894 Letter Lines: 1773 to 1791 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: EPA Proposal: (b) The owner or operator must provide to the Director, at a 

frequency determined by the Director, written updates of adjustments to the cost 

estimate to account for any amendments to the area of review and corrective 

action plan (§ 146.84), the injection well plugging plan (§ 146.92), and the 

post-injection site care and site closure plan (§ 146.93). 

GWPC Recommendations: (b) The owner or operator must provide to the Director, at 

a frequency determined by the Director, but no more frequently than annually, 

written updates or adjustments to the cost estimate to account for any changes 

to: the area of review and corrective action plan (§146.84), the injection well 

plugging plan (§146.92), and the post-injection site care and site closure plan 

(§146.93). 

Rationale: Does this contemplate both upward and downward adjustments? 

Suggest "change" instead of amendments. 

Clarification on what is meant by "updates or adjustments" would be beneficial 

e.g. what is included, at what frequency etc... 

Individual Response: Owners or operators will be required to adjust costs when they are no 

longer adequate, as specified in the GS rule, at §146.85. These baseline estimates can then be 

updated annually and kept current through input from ongoing dialogue between the owner or 

operator and the Director. The cost estimation methodology guidance will also contain 

instructions on how to adjust cost estimates for inflation to help account for the long-term nature 

of GS and will address the need to adjust cost estimates for inflation. 

EPA is developing guidance on financial responsibility for GS wells. The guidance will include a 

discussion on how to estimate costs to assist GS well owners or operators, third party insurers or 

providers of financial instruments, and permitting authorities in developing estimates of the costs 

associated with various GS activities. The guidance is available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

73
EPA did not make the proposed edits, but did extensively revise and clarify the financial 

responsibility requirements. See the final GS rule and preamble for additional information on 

EPA's final approach. 

Letter ID: 0259 Comment ID: 24895 Letter Lines: 1793 to 1804 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5430 2.9.1 Comments on proposed financial responsibility requirements (40 

CFR 146.85) 

Comment: Rule Provision: 146.85(c) 

EPA Proposal: (c) The owner or operator must notify the Director of adverse 

financial conditions such as bankruptcy that may affect the ability to carry out 

injection well plugging and post-injection site care and site closure. 

GWPC Recommendations: (c) The owner or operator must notify the Director of 

adverse financial conditions that may affect the ability to carry out injection 

well plugging and post-injection site care and site closure. 

Rationale: Delete "such as bankruptcy" from (c). Such examples of potential 

circumstances are unnecessary. 

Individual Response: EPA did not make the proposed edits, but did extensively revise and 

clarify the financial responsibility requirements. EPA believes that the Director must be notified 

of bankruptcy specifically, among other adverse financial conditions, because it affects the use of 

financial instrument. See the final GS rule and preamble for additional information on EPA's 

final approach. Please see the final rule and the discussion of financial responsibility in the 

preamble for additional information. 

Letter ID: 0259 Comment ID: 24896 Letter Lines: 1806 to 1824 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: EPA Proposal: (d) The operator must provide an adjustment of the cost estimate 

to the Director if the Director has reason to believe that the original 

demonstration is no longer adequate to cover the cost of injection well plugging 

(as required by § 146.92) and post-injection site care and site closure (as 

required by § 146.93). 

GWPC Recommendations: (d) The operator must provide an adjustment of the cost 

estimate to the Director if the Director has reason to believe that the most 

74
recent demonstration is no longer adequate to cover the cost of injection well 

plugging (as required by § 146.92) and post-injection site care and site closure 

(as required by § 146.93). 

Rationale: The reference should be to the last demonstration not the original 

demonstration 

This is a one time extraordinary event. Regular updates are covered by 

146.85(b). 

Recognize that these will be updated periodically. 

Individual Response: EPA agrees that it is important to periodically update cost estimates that 

support financial responsibility determinations. EPA clarifies that the GS rule, at §146.85(e) 

requires the owner or operator to provide annual updates to the cost estimate to account for any 

amendments to the AoR and corrective action plan, the injection well plugging plan, and the 

PISC and site closure plan. 

Letter ID: 0259 Comment ID: 24897 Letter Lines: 1826 to 1851 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 

146.86) 

Comment: Rule Provision: 146.86 

EPA Proposal: 6. Injection well construction requirements 

(a) General. The owner or operator must ensure that all Class VI wells are 

constructed and completed to: 

(1) Prevent the movement of fluids into or between USDWs or into any 

unauthorized zones; 

(2) Permit the use of appropriate testing devices and workover tools; and 

(3) Permit continuous monitoring of the annulus space between the injection 

tubing and long string casing. 

GWPC Recommendations: (a) General. The owner or operator must ensure that all 

Class VI wells are constructed and completed to: 

(1) Prevent the movement of fluid containing any contaminant into USDWs per 40 

CFR Part 144.12(a). 

(2) Permit the use of appropriate testing devices and workover tools; and 

(3) Permit continuous monitoring of the annulus space between the injection 

tubing and long string casing. 

75
Rationale: Mirror language concerning endangerment standard in (1). 

The GWPC suggests re-wording (a)(1) to simplify and make it consistent with the 

CFR definitions of fluid movement. 

Individual Response: EPA believes that protection of USDWs from endangerment and 

prevention of fluid movement between formations is paramount and believes that the language as 

proposed meets the non-endangerment standard provided in SDWA and §144.12. Appropriately 

designed and constructed wells are necessary to prevent endangerment to USDWs and maintain 

integrity of the well throughout the lifetime of a GS project. This is the foundation of the 

requirements for construction and pre-operational testing of Class VI wells at §§146.86 and 

146.87. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and 

Request for Comment EPA has made many revisions to the GS rule. Please see the final rule and 

preamble for additional information. 

Letter ID: 0259 Comment ID: 24898 Letter Lines: 1853 to 1882 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3860 2.3.3 Well component degradation 

Comment: EPA Proposal: (b) Casing and Cementing of Class VI Wells. 

(1) Casing and cement or other materials used in the construction of each Class 

VI well must have sufficient structural strength and be designed for the life of 

the geologic sequestration project. All well materials must be compatible with 

fluids with which the materials may be expected to come into contact and meet or 

exceed standards developed for such materials by the American Petroleum 

Institute, ASTM International, or comparable standards acceptable to the 

Director. The casing and cementing program must be designed to prevent the 

movement of fluids into or between USDWs. In order to allow the Director to 

determine and specify casing and cementing requirements, the owner or operator 

must provide the following information: 

GWPC Recommendations: (1) Casing and cement or other materials used in the 

construction of each Class VI well must have sufficient structural strength and 

be designed for the life of the operating life of the well. All well materials 

must be compatible with fluids with which the materials may be expected to come 

into contact and meet or exceed test standards or practices developed for such 

materials by the American Petroleum Institute, ASTM International, or comparable 

standards acceptable to the Director. The casing and cementing program must be 

designed to prevent the movement of fluids into or between USDWs. In order to 

allow the Director to determine and specify casing and cementing requirements, 

the owner or operator must provide the following information: 

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Rationale: Suggest substituting "operating life of the well" for "the life of 

the geologic sequestration project" in (1) The GWPC determined that geologic 

sequestration project was a nebulous term that could not be calculated and thus 

would have no meaning in designing a casing or cementing program. 

IMirror the non endangerment standard. 

Individual Response: EPA disagrees that the casing, cement or other materials should only be 

designed for the period of the injection process, rather than the life of the sequestration project. 

GS projects are anticipated to have long life spans in comparison to other types of deep injection 

wells. Not only must Class VI wells be able to function safely and properly over the lifespan of 

the GS project, but they must be constructed such that USDWs remain protected after well 

plugging. The requirements at §146.86 will ensure that the well can maintain integrity 

throughout the proposed life span of the project, including after the injection well is plugged and 

through post-injection site care period and beyond. While the risk profile of a GS site will 

decrease following cessation of injection, EPA believes that Class VI wells must be designed to 

protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and 

cementing help ensure that the Class VI well will not serve as a conduit for movement of fluids 

associated with future injection operations. 

Letter ID: 0259 Comment ID: 24899 Letter Lines: 1884 to 1911 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3860 2.3.3 Well component degradation 

Comment: Rule Provision: 146.86(b)(1) 

EPA Proposal: (i) Depth to the injection zone; 

(ii) Injection pressure, external pressure, internal pressure and axial loading; 

(iii) Hole size; 

(iv) Size and grade of all casing strings (wall thickness, external diameter, 

nominal weight, length, joint specification and construction material); 

(v) Corrosiveness of the carbon dioxide stream, and formation fluids; 

(vi) Down-hole temperatures; 

(vii) Lithology of injection and confining zones; 

GWPC Recommendations: (i) Depth to the injection zone; 

(iii) Hole size; 

(iv) Size and grade of all casing strings (wall thickness, external diameter, 

nominal weight, length, joint specification and construction material); 

(v) Predicted corrosiveness of the combined carbon dioxide stream and formation 

fluids; 

(vi) Down-hole temperatures and pressures; 

(vii) Lithology of injection and confining zones; 

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Rationale: What is meant by external and internal pressure? Recommend deleting 

(ii). 

Insert "and pressures" in (vi) 

Cannot measure the corrosiveness of the CO2 stream because it is not corrosive. 

Only liquids will yield pH measurements. 

Individual Response: EPA disagrees with the suggested edits. The internal and external 

pressure mentioned in §146.86(b)(1)(ii) refers to pressure on the well casing. Internal pressures 

could be caused by cement or annular fluids; external pressures could be caused by cementing 

against the borehole or pressure head from formations. 

At §146.86(c)(3)(ii), EPA clarifies that, although corrosiveness does not have a unit of measure, 

corrosiveness can be technically measured and described. Procedures that can identify corrosion 

(or the absence of corrosion) in a Class VI well provide valuable operational information that the 

Director needs to determine appropriate standards for the tubing and packer. EPA believes that 

this subpart accounts for all characteristics of the CO2 that could affect the performance of the 

tubing and packer, including the chemical content, corrosiveness, temperature, and density. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24900 Letter Lines: 1910 to 1911 

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment: Cannot measure the corrosiveness of the CO2 stream because it is not corrosive. 

Only liquids will yield pH measurements. 

Individual Response: EPA clarifies that, although corrosiveness does not have a unit of 

measure, corrosiveness can be technically measured and described. Procedures that can identify 

corrosion (or the absence of corrosion) in a Class VI well provide valuable operational 

information that the Director needs to determine appropriate standards for the tubing and packer. 

As written, the text at §146.86(c)(3)(ii) accounts for all characteristics of the CO2 that could 

affect the performance of the tubing and packer, including the chemical content, corrosiveness, 

temperature, and density. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

78
Letter ID: 0259 Comment ID: 24901 Letter Lines: 1913 to 1921 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment) 

Comment: EPA Proposal: (viii) Type or grade of cement; and 

(ix) Quantity, chemical composition, and temperature of the carbon dioxide 

stream. 

GWPC Recommendations: (viii) Type or grade of cement and additives; and 

(ix) Quantity, chemical composition, and temperature of the carbon dioxide 

stream. 

Rationale: Insert "and additives" in (viii) 

Individual Response: EPA agrees with the suggestion that §146.86(b)(1)(viii) be revised to also 

address cement additives. In the final GS rule, the subparagraph reads as follows: "Type or grade 

of cement and cement additives." 

Letter ID: 0259 Comment ID: 24902 Letter Lines: 1923 to 1933 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment) 

Comment: EPA Proposal: (2) Surface casing must extend through the base of the lowermost 

USDW and be cemented to the surface. 

GWPC Recommendations: (2) Surface casing must extend through the base of the 

lowermost USDW above the injection zone and be cemented to the surface. 

Rationale: Insert "above the injection zone" in (2) after "USDW." In some parts 

of the US the USDW is very deep and this standard may preclude geologic 

sequestration in these areas. EPA should consider allowing the Director to 

exercise discretion to approve alternative means of achieving continuous cement 

around the well in such areas. 

Individual Response: EPA disagrees with the suggested edit or that the surface casing 

requirements in the GS rule preclude injection below deep USDWs. The final GS rule at 

§146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and 

be cemented to the surface through the use of a single or multiple strings of casing and cement. It 

does not, however, specify how cementing must be accomplished, and gives flexibility to the 

owner or operator to propose alternate methods- to provide a sufficient amount of cement to 

meet the standard that USDWs are protected from endangerment. EPA notes that there are many 

potential ways to meet the requirement, such as the use of staged cementing. 

EPA adds that protection of USDWs is the primary mission and mandate of the UIC program 

79
and the purpose of all requirements for injection wells. Any injection activity must be 

demonstrated to not endanger USDWs, regardless of their depth, and if such a demonstration 

cannot be made, then the activity will not be allowed under UIC requirements or the SDWA. 

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW 

is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 

includes requirements for owners or operators that seek a waiver of the injection depth 

requirements. Owners or operators of wells operating under injection depth waivers must comply 

with additional construction requirements to ensure that wells used to inject above or between 

USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS 

rule for additional information. 

Letter ID: 0259 Comment ID: 24903 Letter Lines: 1935 to 1953 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment) 

Comment: EPA Proposal: (3) At least one long string casing, using a sufficient number of 

centralizers, must extend to the injection zone and must be cemented by 

circulating cement to the surface in one or more stages. 

GWPC Recommendations: (3) At least one long string casing, using a sufficient 

number of centralizers, which at a minimum, would create a cement bond through 

the confining zone, and which must extend to the injection zone and must be 

isolated by placing cement and/or other isolation technologies as necessary to 

provide adequate isolation of the injection zone and provide for protection of 

USDWs. 

Rationale: Cementing to surface is not necessary to protect USDWS, and may have 

negative consequences, as follows. Cement to surface would eliminate the 

ability to monitor pressures in this annulus and would limit flexibility of 

remedial options. As revised, the proposal would allow for application and 

development of alternative technologies. See API RP90 for description of riskbased approach for managing situations involving annular casing pressure. 

Industry experience with CO2 EOR under the class II program demonstrates the 

effectiveness of existing cementing procedures. 

Individual Response: EPA does not believe that the cementing requirements at §146.86 would 

prevent monitoring, operation and remediation of Class VI wells. Cementing of deep wells has 

been performed successfully in the past by owners or operators of Class I hazardous and Class I 

municipal waste disposal wells. Some of these wells, which must meet the same cementing and 

casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully 

cemented in a manner that maintains integrity and allows for all required well testing, operation, 

and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in 

the preamble to the final GS rule for additional information. Additionally, EPA is developing 

80
guidance on the construction of Class VI wells. This guidance will be available on EPA’s 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24904 Letter Lines: 1955 to 1965 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3824 2.3.1.2 Cementing of long-string casing (seeking comment) 

Comment: Rule Provision: 146.86(b) 

EPA Proposal: (4) Circulation of cement may be accomplished by staging. The 

Director may approve an alternative method of cementing in cases where the 

cement cannot be recirculated to the surface, provided the owner or operator can 

demonstrate by using logs that the cement does not allow fluid movement behind 

the well bore. 

GWPC Recommendations: Delete 

Rationale: Same as above 

Individual Response: EPA disagrees that the requirement should be deleted. Section 

146.86(b)(4) of the final rule allows alternate methods of staging the cement, at the Director's 

discretion, provided the owner or operator can demonstrate using logs that the cement does not 

allow fluid movement behind the wellbore. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24905 Letter Lines: 1967 to 1988 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment: EPA Proposal: (5) Cement and cement additives must be compatible with the carbon 

dioxide stream and formation fluids and of sufficient quality and quantity to 

maintain integrity over the design life of the geologic sequestration project. 

The integrity and location of the cement shall be verified using technology 

capable of evaluating cement quality radially and identifying the location of 

channels to ensure that USDWs are not endangered. 

GWPC Recommendations: (5) Cement and cement additives must be suitable for use 

with the carbon dioxide stream and formation fluids and of sufficient quality 

and quantity to maintain integrity over the operating life the well. The 

81
integrity and location of the cement shall be verified using technology capable 

of evaluating cement quality radially and identifying the location of channels 

to ensure that USDWs are not endangered. 

Rationale: Experience with CO2 EOR under the class II program demonstrates the 

effectiveness of existing cementing materials and procedures. Standard API 

cements have been used in numerous CO2 EOR operations without adverse 

consequences. Reference API CO2 EOR report and Carey et al. Bill Carey (SACROC) 

and Walter Crow (CCP2 - placement and annular gap more important than type). 

Once the well is plugged, the plug will isolate the other portions of the well 

from the injected fluids. 

Individual Response: EPA clarifies that the requirement at §146.86(b)(5) is that cement and 

cement additives must be compatible with the CO2 stream and formation fluids and of sufficient 

quality and quantity to maintain integrity over the design life of the GS project. The rule does not 

specify materials to be used; rather, it provides owners or operators with the flexibility to choose, 

as long as the materials used in Class VI wells are compatible with fluids with which they may 

come into contact and meet or exceed standards developed for such materials by API or ASTM 

International, or comparable standards approved by the Director. 

EPA recognizes that the oil and gas industry has decades of experience injecting CO2 for the 

purpose of enhanced recovery, and that this practice has led to the development of many 

measures that would be appropriate for the design of Class VI wells. 

EPA disagrees that the casing, cement or other materials should only be designed for the period 

of the injection process, rather than the life of the sequestration project. GS projects are 

anticipated to have long life spans in comparison to other types of deep injection wells. Not only 

must Class VI wells be able to function safely and properly over the lifespan of the GS project, 

but they must be constructed such that USDWs remain protected after well plugging. The 

requirements at §146.86 will ensure that the well can maintain integrity throughout the proposed 

life span of the project, including after the injection well is plugged and through post-injection 

site care period and beyond. While the risk profile of a GS site will decrease following cessation 

of injection, EPA believes that Class VI wells must be designed to protect USDWs from 

endangerment for the life of the project. Furthermore, rigorous casing and cementing help ensure 

that the Class VI well will not serve as a conduit for movement of fluids associated with future 

injection operations. 

Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance 

will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24906 Letter Lines: 1990 to 2022 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment) 

82
Comment: Rule Provision: 146.86(c) 

EPA Proposal: (c) Tubing and packer. 

(1) All owner and operators of Class VI wells must inject fluids through tubing 

with a packer set at a depth opposite a cemented interval at the location 

approved by the Director. 

(2) In order for the Director to determine and specify requirements for tubing 

and packer, the owner or operator must submit the following information: 

(i) Depth of setting; 

(ii) Characteristics of the carbon dioxide stream (chemical content, 

corrosiveness, temperature, and density); 

GWPC Recommendations: (c) Tubing and packer. 

(1) All owner and operators of Class VI wells must inject fluids through tubing 

with a packer set at a depth opposite a cemented interval at the location 

approved by the Director. 

(2) In order for the Director to determine and specify requirements for tubing 

and packer, the owner or operator must submit the following information: 

(i) Depth of setting; 

(ii) Composition of the carbon dioxide stream; 

Rationale: What does corrosiveness mean? How is it measured? 

Cannot measure the corrosiveness of a carbon dioxide stream. 

Composition of the cO2 stream is needed to design a tubing and packer system. 

The other listed characteristics are not needed. 

Individual Response: As written, the text at §146.86(c)(3)(ii) accounts for all characteristics of 

the CO2 that could affect the performance of the tubing and packer, including the chemical 

content, corrosiveness, temperature, and density. The suggested revision to refer to CO2 

"composition" would be less precise. EPA clarifies that, although corrosiveness does not have a 

unit of measure, corrosiveness can be technically measured and described. Procedures that can 

identify corrosion (or the absence of corrosion) in a Class VI well provide valuable operational 

information that the Director needs to determine appropriate standards for the tubing and packer. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

83
Class VI wells. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24907 Letter Lines: 2024 to 2042 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment) 

Comment: Rule Provision: 146.86(c)(2) 

EPA Proposal: (iii) Injection pressure; 

(iv) Annular pressure; 

(v) Injection rate (intermittent or continuous) and volume of the carbon dioxide 

stream; 

(vi) Size of casing; and 

(vii) Tubing tensile, burst, and collapse strengths. 

GWPC Recommendations: (iii) Maximum proposed Injection temperature and pressure; 

(iv) Maximum proposed Annular pressure; 

(v) Maximum proposed Injection rate (intermittent or continuous) and volume of 

the carbon dioxide stream; 

Rationale: It is more helpful to know the recommended information. 

The GWPC also recommends addition of the term "proposed in (iii), (iv) and (v) 

as this section relates to an application and not to actual established permit 

conditions 

Individual Response: EPA has revised §146.86(c)(3)(iii) and (iv) to reference the maximum 

proposed injection pressure and maximum proposed annular pressure, respectively. EPA has 

revised §146.86(c)(3)(v) to read "proposed injection rate (intermittent or continuous), and 

volume and/or mass of the carbon dioxide stream." EPA believes that reference to the continuous 

injection rate would be duplicative of the maximum rate. EPA believes that considering the 

maximum injection and annular pressure would be more protective. 

Letter ID: 0259 Comment ID: 24909 Letter Lines: 2270 to 2295 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

Comment: Rule Provision: 146.88 

EPA Proposal: 8. Injection well operating requirements 

(a) Except during stimulation, the owner or operator must ensure that injection 

84
pressure does not exceed 90 percent of the fracture pressure of the injection 

zone so as to assure that the injection does not initiate new fractures or 

propagate existing fractures in the injection zone. In no case may injection 

pressure initiate fractures in the confining zone(s) or cause the movement of 

injection or formation fluids that endangers a USDW. 

GWPC Recommendations: (a) The owner or operator must comply with a maximum 

injection pressure limit approved by the Director and specified in the permit. 

In approving a maximum injection pressure limit, the Director shall consider the 

results of well tests and, where appropriate, geomechanical or other studies 

that assess the risks of tensile failure and shear failure. The Director shall 

approve limits that, with a reasonable degree of certainty, will avoid 

initiation or propagation of fractures in the confining zone or cause otherwise 

non-transmissive faults transecting the confining zone to become transmissive. 

In no case may injection pressure cause movement of injection or formation 

fluids in a manner prohibited by 40 CFR Part 144.12(a). 

Rationale: Maintaining the integrity of the confining zone is the critical 

parameter. We believe establishing a maximum pressure based on an arbitrary 

percentage of injection zone fracture pressure does not address the issue of 

confining zone integrity in an appropriate way. 

Individual Response: EPA notes that because determination of the injection pressure limit is 

based on the fracture pressure of the injection zone, the limit is site-specific and not arbitrary. 

EPA emphasizes that injection pressure limits are important to protect against fracturing of the 

confining zone, and that the requirement at §146.88(a) that the pressure in the injection zone not 

exceed 90 percent of the fracture pressure provides a margin of safety in the well operation and 

protects USDWs from endangerment. If the Director determines, based on a review of the 

information collected as part of site characterization, that a lower injection pressure limitation is 

appropriate, the Director has the authority to set a lower limit in the operating permit than the 

limit established in the rule. 

EPA notes that during the site characterization process, owners or operators must submit data 

about the geology of the site, as specified at §146.82(a), including data on known or suspected 

faults and fractures and geomechanical information on fractures, stress, ductility, rock strength, 

and in situ fluid pressures within the confining zone. The Director will use these data to 

determine appropriate limits on injection. 

EPA is developing guidance on site characterization for GS projects to assist owners or operators 

in meeting the requirements of §146.82 and to assist directors in evaluating permit applications. 

The guidance will describe recommended approaches for characterizing the regional geology and 

hydrogeology of a proposed site and performing the necessary geochemical, geomechanical, and 

geophysical analyses of the injection and confining zone. EPA is also developing guidance for 

primacy agencies that will include recommended approaches for evaluating owner or operatorsubmitted data in setting permit conditions. The guidance will be available on EPA's web site, at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

85
Letter ID: 0259 Comment ID: 24910 Letter Lines: 2297 to 2308 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4100 2.4.1 Injection parameters 

Comment: EPA Proposal: (b) Injection between the outer-most casing protecting USDWs and 

the well bore is prohibited. 

GWPC Recommendations: (b) Injection of the CO2 stream between the outermost 

casing protecting USDWs and the well bore is prohibited. 

Rationale: Routine injection into zones other than the target interval(s) should 

be prohibited, however, wording of this requirement is not clear as to which 

interval is being addressed. An absolute prohibition on injection may also 

limit diagnostic options that could be useful. 

Sometimes inject other things to remediate well. 

Individual Response: EPA retains the provision as proposed, and clarifies that injection 

between the casing and the well bore is prohibited. This is consistent with requirements for other 

injection well classes. 

Letter ID: 0259 Comment ID: 24911 Letter Lines: 2310 to 2335 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4100 2.4.1 Injection parameters 

Comment: EPA Proposal: (c) The owner or operator must fill the annulus between the tubing 

and the long string casing with a non-corrosive fluid approved by the Director. 

The owner or operator must maintain on the annulus a pressure that exceeds the 

operating injection pressure, unless the Director determines that such 

requirement might harm the integrity of the well. 

GWPC Recommendations: (c) The owner or operator must fill the annulus between 

the tubing and the long string casing with a corrosion inhibiting fluid approved 

by the Director. The owner or operator must maintain a positive pressure on the 

annulus. 

Rationale: Agency and Industry experience with the Class II UIC program does not 

support this requirement. The standard proposed by EPA is consistent with 

neither the risk level related to CO2 nor the specifications needed to monitor 

the annular space for leakage. 

Rule Provision: 146.88(d) 

86
EPA Proposal: (d) Other than during periods of well workover (maintenance) 

approved by the Director in which the sealed tubing-casing annulus is of 

necessity disassembled for maintenance or corrective procedures, the owner or 

operator must maintain mechanical integrity of the injection well at all times. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA believes that maintaining an annulus pressure that is higher than the 

injection pressure, as required at §146.88(c), is appropriate and will ensure that if there are leaks 

in the tubing, the annulus fluid will move into the tubing, rather than the injectate moving out of 

the tubing and potentially along the outside of the well. EPA believes this requirement is 

appropriate for Class VI wells given the potential high volumes and supercritical nature of the 

CO2 injectate, potential geomechanical stresses in the wellbore, and the potential for movement 

of the CO2 in the event of a mechanical integrity loss. 

EPA disagrees that maintaining an annulus pressure higher than the injection pressure impacts 

continuous pressure monitoring for internal MI. The purpose of continuous pressure monitoring 

(to demonstrate internal MI) is to demonstrate that no pressure changes are occurring, because a 

drop in pressure on the annulus provides an early indication that attention is needed to prevent a 

loss of MI or unacceptable fluid movement. EPA believes that any change in the pressure on the 

annulus between tubing and long stem casing, regardless of what the annulus pressure is relative 

to injection pressure, can indicate a leak. 

EPA agrees with the commenter that maintaining mechanical integrity is an essential component 

of protecting USDWs. The final rule retains a requirement to maintain mechanical integrity at 

§146.88(d). 

Letter ID: 0259 Comment ID: 24912 Letter Lines: 2337 to 2362 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment) 

Comment: Rule Provision: 146.88 

EPA Proposal: (e) The owner or operator must install and use continuous 

recording devices to monitor: The injection pressure; the rate, volume, and 

temperature of the carbon dioxide stream; and the pressure on the annulus 

between the tubing and the long string casing and annulus fluid volume; and must 

install and use alarms and automatic down-hole shut-off systems, designed to 

alert the operator and shut-in the well when operating parameters such as 

annulus pressure, injection rate or other parameters approved by the Director 

diverge beyond permitted ranges and/or gradients specified in the permit; 

GWPC Recommendations: (e) The owner or operator must install and use continuous 

87
recording devices to monitor: the injection pressure; the rate, volume, and 

temperature of the carbon dioxide stream. The owner or operator must regularly 

monitor the pressure on the annulus between the tubing and the long string 

casing. The owner or operator must install, test and use alarms and automatic 

shut-off systems, designed to alert the operator and shut-in the well when 

operating parameters such as injection rate, injection pressure, or other 

parameters approved by the Director diverge beyond ranges and/or gradients 

specified in the permit; 

Rationale: Over-pressure protection is best achieved by ensuring compatibility 

of the casing/tubing material design strength with the surface injection 

(compression) system. Down-hole shut-in devices may be appropriate, however, 

for site-specific situations of unique potential impact (such as offshore or 

near airports), but they should not be mandated for all injection sites. 

Individual Response: EPA acknowledges that proper design of the well, including appropriate 

materials and emplacement of casing and tubing, is essential to proper operation of the well so 

that USDWs are protected. Such design, however, does not eliminate the possibility of failure, 

e.g., due to over-pressurization as suggested by the commenter. EPA believes that a multiplebarrier approach, which includes appropriate well design as required at §146.86, suitable 

injection pressure limits as required at §146.88(a), and automatic shut-off systems, as required at 

§146.88(e), is necessary to ensure protection of USDWs from endangerment from the risks 

associated with CO2 GS. 

After evaluating the risks and benefits of down-hole shut-off systems and considering additional 

research, EPA will not require automatic down-hole shut-off devices for onshore Class VI wells 

since it is not necessary in all cases to ensure protection of USDWs from endangerment. Instead, 

the final rule, at §146.88(e)(2), requires that owners or operators of onshore Class VI wells 

install automatic surface shut-off devices. The rule affords Director's discretion to mandate 

automatic down-hole shut-off devices in onshore situations that may warrant their use. However, 

the Agency believes that offshore Class VI wells present unique construction and operational 

conditions, including isolation from shorelines and the need to construct wells through the water 

column and the subsurface, which may delay response time in the event of well difficulties. The 

rule requires, at §146.88(e)(3), that owners or operators of offshore wells within State territorial 

waters install automatic down-hole shut-off systems. EPA believes that these requirements at 

§146.88(e) ensure that proper precautions are taken to prevent subsurface fluid movement and 

ensure protection of USDWs. 

While EPA acknowledges that the likelihood of damage to onshore facilities is lower than that 

for off-shore facilities, down-hole shut-off valves are still commonly used in onshore facilities 

such as acid gas injection wells and high pressure, high-temperature wells. While valve failure is 

a concern, EPA believes that technology has advanced sufficiently to make valve failure a rare 

occurrence and to appropriately handle such failure if it occurs. For example, wireline retrievable 

devices can allow repair or replacement of damaged devices without necessitating pulling the 

tubing. 

88
Letter ID: 0259 Comment ID: 24913 Letter Lines: 2364 to 2388 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment) 

Comment: Rule Provision: 146.88 

EPA Proposal: (f) If a down-hole automatic shutdown is triggered or a loss of 

mechanical integrity is discovered, the owner or operator must immediately 

investigate and identify as expeditiously as possible the cause of the shutoff. 

If, upon such investigation, the well appears to be lacking mechanical 

integrity, or if monitoring required under paragraph (e) of this section 

otherwise indicates that the well may be lacking mechanical integrity, the owner 

or operator must: 

GWPC Recommendations: (f) If an automatic shutdown is triggered or a loss of 

mechanical integrity is discovered, the owner or operator must immediately 

investigate and identify as expeditiously as possible the cause. If, upon such 

investigation, the well appears to be lacking mechanical integrity, or if 

monitoring required under paragraph (e) of this section otherwise indicates that 

the well may be lacking mechanical integrity, the owner or operator must: 

Rationale: Eliminates requirement for down-hole shutoff device. Although the 

use of downhole shutoff valves may be needed in some applications, their 

required use would be less than ideal for many reasons such as the fact that 

since they are a downhole installation, integrity and maintenance of the valves 

is difficult. Further the installation of surface valves would allow for more 

control and provide for visual inspection. Since the key is to shut down the 

injection flow if a parameter is exceeded, the use of surface valves would be 

just as effective as downhole valves. 

Individual Response: As described above, EPA will not require automatic down-hole shut-off 

devices for onshore Class VI wells since it is not necessary in all cases to ensure protection of 

USDWs from endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or 

operators of onshore Class VI wells install automatic surface shut-off devices. The rule affords 

Director's discretion to mandate automatic down-hole shut-off devices in onshore situations that 

may warrant their use. The rule requires, at §146.88(e)(3), that owners or operators of offshore 

wells within State territorial waters install automatic down-hole shut-off systems. Please see the 

final rule and preamble for additional information on EPA's final approach. 

Letter ID: 0259 Comment ID: 24914 Letter Lines: 2390 to 2409 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4000 2.4 Proposed Injection Well Operating Requirements (40 CFR 146.88) 

Comment: Rule Provision: 146.88(f) 

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EPA Proposal: (1) Immediately cease injection; 

(2) Take all steps reasonably necessary to determine whether there may have been 

a release of the injected carbon dioxide stream into any unauthorized zone; 

(3) Notify the Director within 24 hours; 

(4) Restore and demonstrate mechanical integrity to the satisfaction of the 

Director prior to resuming injection; and 

(5) Notify the Director when injection can be expected to resume. 

GWPC Recommendations: Support the proposed EPA language for (1), (2), and (5) 

(3) Notify the Director within 24 hours of discovery; 

(4) Restore and demonstrate mechanical integrity to the satisfaction of the 

director as soon as practicable and prior to resuming injection. 

Rationale: Needs to be reasonable and allow for time following discovery. 

It was felt that some timeframe for restoration of mechanical integrity should 

be added to (4) 

Individual Response: The final rule text at §146.88(f) now reads, "If a shutdown (i.e., downhole or at the surface) is triggered or a loss of mechanical integrity is discovered." Therefore the 

notice required at §146.88(f)(3) must be provided within 24 hours of an automatic shut-off 

device being triggered or a loss of mechanical integrity being discovered. EPA believes this 

provision is necessary to ensure timely response to potential USDW endangerment. 

Letter ID: 0259 Comment ID: 24915 Letter Lines: 2411 to 2423 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4500 2.5 Proposed Mechanical Integrity Testing (MIT) Requirements (40 CFR 

146.89) 

Comment: Rule Provision: 146.89 

EPA Proposal: 9. Mechanical integrity 

(a) A Class VI well has mechanical integrity if: 

(1) There is no significant leak in the casing, tubing or packer; and 

(2) There is no significant fluid movement into a USDW through channels adjacent 

to the injection well bore. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

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Individual Response: EPA acknowledges the comment and the final rule retains the text at 

146.89(a) as proposed. For additional information, please see the discussion of MITs in the final 

rule preamble. 

Letter ID: 0259 Comment ID: 24916 Letter Lines: 2425 to 2440 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4520 2.5.1 Continuous internal mechanical integrity monitoring (seeking 

comment) 

Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment: EPA Proposal: (b) To evaluate the absence of significant leaks under paragraph 

(a)(1) of this section, owners or operators must, following an initial annulus 

pressure test, continuously monitor injection pressure, rate, injected volumes, 

and pressure on the annulus between tubing and long stem casing and annulus 

fluid volume as specified in § 146.88(e); 

GWPC Recommendations: (b) To evaluate the absence of significant leaks under 

paragraph (a)(1) of this section, owners or operators must, following an initial 

annulus pressure test, continuously monitor and record at least daily injection 

pressure, rate, injected volumes, and pressure on the annulus between tubing 

and long stem casing and annulus fluid volume as specified in §146.88 (e); 

Rationale: We believe that injection parameters must not only be monitored but 

should be recorded at least daily. We further believe the use of monitoring with 

digital equipment which records readings on an appropriate frequency should be 

considered continuous for purposes of this section. 

Individual Response: EPA believes that continuous pressure monitoring to demonstrate internal 

mechanical integrity of Class VI wells required at §146.89(b) is important, given the potential 

corrosive impact of CO2 and impurities on well materials, the potential geomechanical impacts 

to well integrity due to CO2 phase changes, and the temperature and pressure effects associated 

with injecting supercritical CO2. EPA also believes that the technology for continuous 

monitoring is practicable, available, and is currently in fairly wide use. Class VI injection wells 

will be equipped with dedicated computer-based continuous pressure monitoring devices (in 

concert with the shut-off systems required for GS wells), which typically take readings several 

times per second (i.e., more frequently than daily) and record them electronically in a computer 

system. 40 CFR §146.91(a)(2) requires that monthly averages of the continuous annulus 

monitoring be reported on a semiannual basis. For additional information, please see the 

discussion of MITs in the final rule preamble. 

Letter ID: 0259 Comment ID: 24917 Letter Lines: 2442 to 2462 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4540 2.5.2 Proposed external MIT requirements 

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Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: Rule Provision: 146.89(c) 

EPA Proposal: (c) At least once per year, the owner or operator must use one of 

the following methods to determine the absence of significant fluid movement 

under paragraph (a)(2) of this section: 

(1) A tracer survey such as oxygen-activation logging; 

(2) A temperature or noise log; or 

(3) A casing inspection log, if required by the Director. 

GWPC Recommendations: (c) At least once per year, the owner or operator must 

confirm the absence of significant fluid movement under paragraph (a)(2) of this 

section using a method acceptable to the Director (e.g. including diagnostic 

surveys such as oxygen-activation logging or temperature or noise logs). 

Delete (1) 

Delete (2) 

Delete (3) 

Rationale: Revised text supports a performance-based approach and allows the 

development and use of new technologies as they become available. 

Individual Response: EPA believes that the MITs described in §146.89(c) of the rule (e.g., an 

approved tracer log or temperature or noise logs) are effective methods to demonstrate external 

MI, provide an important early warning of potential problems in the injection well system, and 

represent standard techniques that have been used successfully by the drilling industry and for 

the UIC Program for decades. The Agency notes that the regulations do provide the Director 

flexibility at §146.89(e) to approve the use of alternative MIT methods. 

EPA agrees that the casing inspection log is not an appropriate test to detect fluid movement 

behind the casing, but clarifies that it is appropriate to be used to determine the presence or 

absence of corrosion of the long-string casing, and is required if the Director determines that it is 

necessary based on site-specific information. EPA has revised the final GS rule to require that 

the frequency of the casing inspection log must be specified in the approved testing and 

monitoring plan. See §146.89(d). 

Letter ID: 0259 Comment ID: 24918 Letter Lines: 2464 to 2478 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: EPA Proposal: (d) The Director may require any other test to evaluate mechanical 

integrity under paragraph (a)(1) or (a)(2) of this section. Also, the Director 

92
may allow the use of a test to demonstrate mechanical integrity other than those 

listed above with the written approval of the Administrator. To obtain 

approval, the Director must submit a written request to the Administrator, which 

must set forth the proposed test and all technical data supporting its use. The 

Administrator must approve the request if it will reliably demonstrate the 

mechanical integrity of wells for which its use is proposed. Any alternate 

method approved by the Administrator will be published in the Federal Register 

and may be used in all States in accordance with applicable State law unless its 

use is restricted at the time of approval by the Administrator. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment and the final rule retains the text as 

proposed. 

Letter ID: 0259 Comment ID: 24919 Letter Lines: 2480 to 2492 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: Rule Provision: 146.89(e) 

EPA Proposal: (e) In conducting and evaluating the tests enumerated in this 

section or others to be allowed by the Director, the owner or operator and the 

Director must apply methods and standards generally accepted in the industry. 

When the owner or operator reports the results of mechanical integrity tests to 

the Director, he/she shall include a description of the test(s) and the 

method(s) used. In making his/her evaluation, the Director must review 

monitoring and other test data submitted since the previous evaluation. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment and the final rule retains the text as 

proposed. 

Letter ID: 0259 Comment ID: 24920 Letter Lines: 2494 to 2503 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: EPA Proposal: (f) The Director may require additional or alternative tests if 

93
the results presented by the owner or operator under paragraph (d) of this 

section are not satisfactory to the Director to demonstrate that there is no 

significant leak in the casing, tubing or packer or significant movement of 

fluid into or between USDWs resulting from the injection activity as stated in 

paragraphs (a)(1) and (2) of this section. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment and the final rule retains the text as 

proposed. 

Letter ID: 0259 Comment ID: 24922 Letter Lines: 2505 to 2518 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment) 

Comment: Rule Provision: 146.90 

EPA Proposal: 10. Testing and monitoring requirements 

The owner or operator of a Class VI well must prepare, maintain, and comply with 

a testing and monitoring plan to verify that the geologic sequestration project 

is operating as permitted and is not endangering USDWs. The testing and 

monitoring plan must be submitted with the permit application, for Director 

approval, and must include a description of how the owner or operator will meet 

the requirements of this section. Testing and monitoring associated with 

geologic sequestration projects must, at a minimum, include: 

GWPC Recommendations: Support the proposed EPA language. 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

rule and NODA and Request for Comment EPA has made many revisions to the GS rule. See the 

final rule and preamble for further discussion on EPA's final approach. 

EPA agrees with commenters that developing and following testing and monitoring plans is an 

important part of assuring that a GS project is operating properly and is crucial for the early 

detection of potential endangerment to USDWs. 

Letter ID: 0259 Comment ID: 24923 Letter Lines: 2521 to 2540 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 

94
CFR 146.90) 

Comment: Rule Provision: 146.90 

EPA Proposal: (a) Analysis of the carbon dioxide stream with sufficient 

frequency to yield data representative of its chemical and physical 

characteristics; 

(b) Installation and use, except during well workovers as defined in § 

146.86(d), of continuous recording devices to monitor injection pressure, rate 

and volume; the pressure on the annulus between the tubing and the long string 

casing; and the annulus fluid volume; 

GWPC Recommendations: Support the proposed EPA language in (a) 

(b) Installation and use, except during well workovers as defined in §146.88(d), 

of continuous monitoring devices (including digital devices capturing periodic 

data) to monitor injection pressure, rate and volume; and record at least daily 

the pressure on the annulus between the tubing and the long string casing; 

Rationale: 146.86(d) does not exist; perhaps 146.88(d) is what was apparently 

intended. 

Individual Response: EPA acknowledges the comment; the final rule retains the language in 

§146.90(a) as proposed. EPA adds that the final GS rule references §146.88(e), as the commenter 

suggests. 

Regarding §146.90(b), based on its evaluation of all public comments and input on the proposed 

rule and NODA and Request for Comment EPA has made many revisions to the GS rule. See the 

final rule and preamble for further discussion on EPA's final approach. 

Letter ID: 0259 Comment ID: 24924 Letter Lines: 2542 to 2560 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: Rule Provision: 146.90 

EPA Proposal: (c) Corrosion monitoring of the well materials for loss of mass, 

thickness, cracking, pitting and other signs of corrosion must be performed on a 

quarterly basis to ensure that the well components meet the minimum standards 

for material strength and performance set forth in § 146.86(b) by: 

GWPC Recommendations: c) Corrosion monitoring of the well materials for loss of 

mass, thickness, cracking, pitting and other signs of corrosion must be 

performed and recorded at least quarterly and may be modified to be less 

95
frequent as approved by the Director based on construction materials, operating 

conditions, and monitoring history to ensure that the well components meet the 

minimum standards for material strength and performance set forth in §146.86(b) 

by: 

Rationale: Allows application of performance based approach. 

Rationale: Allows less frequent monitoring, for example, where corrosion 

resistant materials are used. 

Individual Response: EPA believes that quarterly corrosion monitoring is appropriate given the 

potentially corrosive nature of the CO2 stream. CO2 in the presence of water becomes acidic, 

potentially accelerating corrosion of well materials. The CO2 stream for a GS project may also 

contain small volumes of impurities that could contribute to corrosion. For these reasons, the 

final rule requires quarterly corrosion monitoring, at §146.90(c). 

Based on its evaluation of all public comments and input on the proposed rule and NODA and 

Request for Comment EPA has made many revisions to the GS rule. See the final rule and 

preamble for further discussion on EPA's final approach. 

Letter ID: 0259 Comment ID: 24925 Letter Lines: 2562 to 2577 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: Rule Provision: 146.90(c) 

EPA Proposal: (1) Placing coupons of the well construction materials in contact 

with the carbon dioxide stream; or 

(2) Routing the carbon dioxide stream through a loop constructed with the 

material used in the well; or 

(3) Using an alternative method approved by the Director; 

GWPC Recommendations: (1) Analyzing coupons of the well construction materials 

placed in contact with the carbon dioxide stream; or 

(2) Routing the carbon dioxide stream through a loop constructed with the 

material used in the well and inspecting the materials in the loop; or 

(3) Using an alternative method, materials, or time period approved by the 

Director; 

Rationale: Clarification edits 

Individual Response: As described above, EPA believes that quarterly corrosion monitoring is 

appropriate given the potentially corrosive nature of the CO2 stream. Based on its evaluation of 

all public comments and input on the proposed rule and NODA and Request for Comment EPA 

96
has made many revisions to the GS rule. See the final rule and preamble for further discussion on 

EPA's final approach. 

Letter ID: 0259 Comment ID: 24926 Letter Lines: 2579 to 2613 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4660 2.6.6 Geochemical monitoring 

Comment: Rule Provision: 146.90(d) 

EPA Proposal: (d) Periodic monitoring of the ground water quality and 

geochemical changes above the confining zone(s) that may be a result of carbon 

dioxide movement through the confining zone or additional identified zones: 

(1) The location and number of monitoring wells must be based on specific 

information about the geologic sequestration project, including injection rate 

and volume, geology, the presence of artificial penetrations and other factors; 

(2) The monitoring frequency and spatial distribution of monitoring wells must 

be based on baseline geochemical data that has been collected under § 146.82(a) 

(6) and any modeling results in the area of review evaluation required by § 

146.84(b); 

GWPC Recommendations: (d) Periodic monitoring of reservoir formation fluid 

quality in a permeable and porous formation as near as practicable to the 

confining zone(s) for geochemical changes that may be a result of carbon dioxide 

or displaced formation fluid movement: 

(1) The location and number of monitoring wells must be based on specific 

information about the geologic sequestration project, including injection rate 

and volume, geology, the presence of artificial penetrations and other relevant 

factors as warranted by a risk-assessment; 

(2) The monitoring frequency and spatial distribution of monitoring wells must 

be based on geological, geochemical and geophysical data that has been collected 

under §146.82(d) and any modeling results in the area of review evaluation 

required by §146.84(b); 

Rationale: Drilling monitoring wells should be carefully considered since each 

well introduces a potential pathway for movement. 

[Geochemical data do not have a high degree of relevance in selecting monitoring 

well sites.] 

Individual Response: EPA believes that monitoring using wells in the injection zone, e.g., for 

pressure monitoring as required at §146.90(g)(1), can be safely performed if the wells are 

97
constructed to prevent flow between the injection zone and USDWs or other layers above the 

confining zone. Such construction technologies exist and have been used in the oil and gas 

industry for years. EPA believes that properly constructed monitoring wells will be a safe way to 

obtain the data that is essential to ensure that the injected CO2 remains confined in the injection 

zone and that pressure changes are not causing movement of formation or other fluids. To 

mitigate the risk of fluid movement, EPA requires owners and operators to submit a testing and 

monitoring plan that describes how the owner or operator plans to site and construct monitoring 

wells. EPA has developed a brief technical paper on construction of monitoring wells that 

perforate the confining zone; this paper can be found in the rulemaking docket. EPA is also 

developing guidance on well construction that will include recommendations for monitoring well 

construction. The guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Baseline characterization of the site, including the geochemical data and initial modeling, will be 

highly valuable in selection of monitoring well locations and in refining plans for monitoring 

frequency. The GS rule stipulates that the monitoring frequency and spatial distribution of 

monitoring wells must be based on baseline geochemical data that were collected during the 

initial site characterization and the area of review evaluation (§146.90(d)(2)). The details of the 

geochemical monitoring must be based on site-specific information and described in the 

Director-approved testing and monitoring plan. 

Letter ID: 0259 Comment ID: 24927 Letter Lines: 2615 to 2632 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 

CFR 146.90) 

Comment: Rule Provision: 146.90 

EPA Proposal: (e) A demonstration of external mechanical integrity pursuant to § 

146.89(c) at least once per year throughout the duration of the geologic 

sequestration project; 

(f) A pressure fall-off test at least once every five years unless more frequent 

testing is required by the Director based on site specific information; 

GWPC Recommendations: (e) A demonstration of external mechanical integrity 

pursuant to §146.89(c) at least once per year until the well is plugged; 

(f) A pressure fall-off test or other equivalent test that identifies reservoir 

conditions with respect to flow dynamics at least once every five years unless 

more frequent testing is required by the Director based on site specific 

information; 

Rationale: Redundant to section 146.89 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

98
rule and NODA and Request for Comment EPA has made many revisions to the GS rule. See the 

final rule and preamble for further discussion on EPA's final approach. 

EPA believes that pressure fall-off testing is necessary for GS wells. Pressure fall-off tests are 

designed to verify that modeled projections of reservoir pressure decline agree with measured 

pressure decline profiles. These tests can be useful in AoR calculations and reevaluations and 

may also indicate mischaracterization of site geology and the presence of leakage pathways. EPA 

therefore believes that pressure fall-off testing is necessary every five years at a minimum, and 

the final GS regulation includes this requirement at §146.90(f). Pressure fall-off tests may be 

conducted in conjunction with other well performance tests (i.e., mechanical integrity testing) to 

ensure safe and effective operations. 

Letter ID: 0259 Comment ID: 24928 Letter Lines: 2634 to 2646 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4650 2.6.5 CO2 plume and pressure front tracking (seeking comment) 

Comment: EPA Proposal: (g) Testing and monitoring to track the extent of the carbon 

dioxide plume and the position of the pressure front by either monitoring for 

pressure changes in the first formation overlying the confining zone or using 

indirect, geophysical techniques (e.g., seismic, electrical, gravity, or 

electromagnetic surveys and/or down-hole carbon dioxide detection tools); 

GWPC Recommendations: (g) Testing and monitoring to track the extent of the 

carbon dioxide plume and the position of the pressure front. 

Rationale: Monitoring outside of the injection zone provides little information 

of value for tracking and monitoring the injected plume. Examples of how to 

test and monitor could be included in the Preamble but need not be included in 

the rule itself. 

Individual Response: EPA has revised this requirement in the final rule. The final GS 

regulation, at §146.90(g)(1), requires all GS project owners or operators to monitor for pressure 

changes in the injection zone. EPA believes that pressure monitoring in the injection zone is 

necessary to track the development and movement of the pressure front and CO2 plume. 

Pressure monitoring within the injection zone is necessary because any such monitoring above 

the confining zone would not detect movement of the pressure front unless a breach of the 

confining zone occurs. EPA believes that monitoring using wells in the injection zone (i.e., that 

penetrate the confining zone) can be safely performed if the wells are constructed to prevent flow 

between the injection zone and USDWs or other layers above the confining zone. Such 

construction technologies exist and have been used in the oil and gas industry for years. EPA 

believes that the benefits of monitoring in the injection formation outweigh the manageable risk 

of those monitoring wells serving as conduits for fluid movement. EPA adds that owners or 

operators may consider performing additional pressure monitoring in wells that are above the 

confining zone (e.g., in the same wells used to perform ground water quality monitoring required 

99
at §146.90(d)) to provide additional verification that no pressure changes are occurring above the 

confining zone due to CO2 leakage. Monitoring also identifies needed remedial actions, provides 

inputs for AoR reevaluation modeling, and targets additional geochemical and surface 

monitoring needs. Knowledge of the location of the CO2 plume and the associated pressure front 

will assure the public that GS projects are proceeding according to plan, provide sufficient 

information to the owner or operator and Director, or allow for appropriate actions to address any 

indication that USDWs may be endangered. 

EPA acknowledges that, at certain sites, there may be a need for more or different monitoring 

schemes (which may include monitoring in the confining zone), and adds that it is important to 

balance the need for adequate monitoring that ensures USDW protection from endangerment 

against too many artificial penetrations which could serve as conduits for fluid migration. Sitespecific testing and monitoring plans should describe the proposed monitoring regime, which 

must be approved by the Director. 

Flexibility is also provided regarding how to monitor for the specific data required by the final 

rule. The testing and monitoring plan is developed by the owner or operator in consultation with 

the Director and is designed to ensure that a detailed, Director-approved document describing 

how monitoring will be conducted during the lifetime of the project exists. EPA is developing 

guidance on testing and monitoring to assist owners or operators and Directors in evaluating 

requirements under §146.90, including proposed monitoring plans. The guidance describes 

available technologies and recommended approaches for implementing a testing and monitoring 

plan, including pre-operational geophysical logging and testing of injection wells, MITs, 

injection well testing during operation, groundwater quality monitoring, tracking the CO2 plume 

and pressure front, and soil gas and surface air monitoring which may be required by the UIC 

Director for specific GS projects. The guidance can be found on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24929 Letter Lines: 2648 to 2659 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking 

comment) 

Comment: Rule Provision: 146.90 

EPA Proposal: (h) At the Director’s discretion, surface air monitoring and/or 

soil gas monitoring to detect movement of carbon dioxide that could endanger a 

USDW. 

GWPC Recommendations: (h) At the Director’s discretion based on site-specific 

conditions and risk-based factors, surface air monitoring and/or soil gas 

monitoring to detect movement of carbon dioxide that could endanger a USDW. 

Rationale: In most situations soil and air monitoring does not provide an 

effective method of protecting USDWs. 

100
Individual Response: As described above, EPA acknowledges that air and soil gas monitoring 

are subject to site-specific limitations and may not be suitable in all settings as a method to 

ensure USDW protection. However, EPA does not believe that this should entirely preclude their 

use. The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring at 

the discretion of the Director as a means of identifying leaks that may pose a risk to USDWs and 

informing emergency notification of a Class VI owner or operator and UIC Director in the event 

of a USDW endangerment, pursuant to requirements at §146.91(c). 

Letter ID: 0259 Comment ID: 24930 Letter Lines: 2661 to 2679 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment) 

Comment: Rule Provision: 146.90(h) 

EPA Proposal: (1) The testing and monitoring plan must be based on potential 

vulnerabilities within the area of review; 

(2) The monitoring frequency and spatial distribution of surface air monitoring 

and/or soil gas monitoring must reflect baseline data and the monitoring plan 

must include how the proposed monitoring will yield useful information on the 

area of review delineation and/or compliance with standards under 40 CFR 144.12; 

GWPC Recommendations: (1) The testing and monitoring plan must be based on sitespecific geologic factors, modeling, and risk-assessment within the area of 

review; 

(2) Agree with EPA language 

Rationale: The GWPC feels that the term "potential vulnerabilities" is too 

nebulous. We suggest replacing this term with the term "site-specific geologic 

factors, modeling, and risk-assessment." 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

rule and NODA and Request for Comment EPA has made many revisions to the GS rule. See the 

final rule and preamble for further discussion on EPA's final approach. 

EPA anticipates that the testing and monitoring plan will address site-specific geologic factors, 

modeling, and risk-assessment. EPA is developing guidance on how best to develop the various 

required project plans, including the testing and monitoring plan. The guidance can be found on 

EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 24931 Letter Lines: 2681 to 2693 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

101
Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment) 

Comment: Rule Provision: 146.90(i) 

EPA Proposal: (i) Any additional monitoring, as required by the Director, 

necessary to support, upgrade, and improve computational modeling of the area of 

review evaluation required under § 146.84(b) and to determine compliance with 

standards under 40 CFR 144.12; and 

(j) A quality assurance and surveillance plan for all testing and monitoring 

requirements. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. The final rule retains these provisions 

as proposed. 

Letter ID: 0259 Comment ID: 24932 Letter Lines: 2695 to 2715 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4760 2.7.6 Proposed reporting frequency (seeking comment) 

Comment: Rule Provision: 146.91 

11. Reporting requirements. 

The owner or operator must, at a minimum, provide the following reports to the 

Director, for each permitted Class VI well: 

(a) Semi-annual reports containing: 

(1) Any changes to the physical, chemical and other relevant characteristics of 

the carbon dioxide stream from the proposed operating data; 

(2) Monthly average, maximum and minimum values for injection pressure, flow 

rate and volume, and annular pressure; 

GWPC Recommendations: (a) Semi-annual or at a frequency determined by the 

Director reports containing: 

(1) Any significant changes to the physical, chemical and other relevant 

characteristics of the carbon dioxide stream from the proposed operating data; 

Rationale: Should be semi-annual unless otherwise determined 

102
Individual Response: EPA is retaining the semi-annual reporting requirements as proposed at 

§146.91(a). These requirements ensure the Director has the information needed to take 

preventive action in a timely manner to protect USDWs from endangerment. For additional 

information, please see the final rule and the preamble for a discussion of EPA's final approach 

to recordkeeping and reporting. 

Letter ID: 0259 Comment ID: 24933 Letter Lines: 2717 to 2735 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Rule Provision: 146.91(a) 

EPA Proposal: (3) A description of any event that exceeds operating parameters 

for annulus pressure or injection pressure as specified in the permit; 

(4) A description of any event which triggers a shutdown device required 

pursuant to § 146.88(e) and the response taken; 

(5) The monthly volume of the carbon dioxide stream injected over the reporting 

period and project cumulatively; 

(6) Monthly annulus fluid volume added; and 

(7) The results of monitoring prescribed under § 146.90. 

GWPC Recommendations: (3) A description of any event that significantly exceeds 

operating parameters for annulus pressure or injection pressure as specified in 

the permit; 

(4) A description of any event which triggers a shutdown device required 

pursuant to §146.88(e) and the response taken; 

Rationale: EPA should consider some significance threshold on reporting these 

events, to avoid reporting events would be of limited interest or consequence. 

Individual Response: EPA retained this provision as proposed. The final rule at §146.91(a)(3) 

requires reporting of all exceedances of operating parameters. EPA disagrees with the suggestion 

to report only "significant" exceedances. Making a determination as to whether an exceedance is 

"significant" is not the purpose of the requirement. EPA believes that the ability of an operator to 

consistently meet operating requirements and avoid exceedances provides evidence of a wellmanaged GS project that is in compliance with the Class VI permit. If multiple exceedances 

occur, the Director should be aware of such occurrences, and that information will aid in his/her 

determination of whether these indicate problems at the site, and what is the appropriate course 

of action (e.g., a well workover, modification of operating parameters, or imposition of a 

penalty) to remediate such problem(s). 

Letter ID: 0259 Comment ID: 24934 Letter Lines: 2737 to 2750 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

103
Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment) 

Comment: EPA Proposal: (b) Report, within 30 days the results of: 

(1) Periodic tests of mechanical integrity; 

(2) Any other test of the injection well conducted by the permittee if required 

by the Director; and 

(3) Any well workover. 

(c) Owners or operators must submit reports in an electronic format acceptable 

to the Director. At the discretion of the Director, other formats may be 

accepted. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. Please see the final rule and the 

discussion of reporting preamble for additional information on EPA's final rulemaking approach. 

EPA believes that electronic formatting is the most appropriate format for submitting Class VI 

project information to the Director, and that many GS well owners or operators will have the 

capability to report electronically. 

Letter ID: 0259 Comment ID: 24935 Letter Lines: 2752 to 2766 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: Rule Provision: 146.92 

EPA Proposal: 12. Injection well plugging. 

(a) Prior to the well plugging, the owner or operator must flush each Class VI 

injection well with a buffer fluid, determine bottomhole reservoir pressure, and 

perform a final mechanical integrity test. 

GWPC Recommendations: (a) Prior to the well plugging, the owner or operator must 

flush each Class VI injection well with a buffer fluid, determine bottomhole 

reservoir pressure, and perform a final external mechanical integrity test. 

Rationale: Many of the components that would be tested by an internal MIT are 

removed or tested during the plugging process. Consequently, the GWPC suggests 

including the term internal to the language for clarification. 

104
Individual Response: EPA agrees that only an external MIT is required, and has modified the 

GS rule at §146.92(a) to require owners or operators to perform a final external mechanical 

integrity test prior to the well plugging. 

Letter ID: 0259 Comment ID: 24936 Letter Lines: 2768 to 2779 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: Rule Provision: 146.92(b) 

EPA Proposal: (b) Well Plugging Plan. The owner or operator of a Class VI well 

must prepare, maintain, and comply with a plan that is acceptable to the 

Director. The requirement to maintain and implement an approved plan is 

directly enforceable regardless of whether the requirement is a condition of the 

permit. The well plugging plan must be submitted as part of the permit 

application and must include the following information: 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the commenter’s support; the final rule retains this 

provision. 

Letter ID: 0259 Comment ID: 24937 Letter Lines: 2781 to 2803 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: EPA Proposal: (1) Appropriate test or measure to determine bottomhole reservoir 

pressure; 

(2) Appropriate testing methods to ensure mechanical integrity as specified in § 

146.89; 

(3) The type and number of plugs to be used; 

(4) The placement of each plug including the elevation of the top and bottom of 

each plug; 

(5) The type and grade and quantity of material to be used in plugging. The 

material must be compatible with the carbon dioxide stream; and 

(6) The method of placement of the plugs. 

GWPC Recommendations: Support the proposed EPA language for (1), (3), (4) and 

105
(6) 

(2) Appropriate testing methods to ensure final external mechanical integrity as 

specified in §146.89(c); 

(5) The type and grade and quantity of material to be used in plugging. The 

material must be suitable for use with the carbon dioxide stream; and 

Rationale: Many of the components that would be tested by an internal MIT are 

removed or tested during the plugging process. Consequently, the GWPC suggests 

adding the term external to the language for clarification. 

Individual Response: Regarding the suggested edit at 146.92(b)(2), EPA agrees that only an 

external MIT is required, and has modified the GS rule at §146.92(a) to require owners or 

operators to perform a final external mechanical integrity test prior to the well plugging. 

Regarding the edit at 146.92(b)(5), EPA believes, considering the potentially corrosive nature of 

CO2 when it is in contact with water, that the requirement that the material must be compatible 

with the CO2 stream is appropriate. The final rule retains this requirement. 

Letter ID: 0259 Comment ID: 24938 Letter Lines: 2805 to 2813 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: EPA Proposal: (c) Notice of intent to plug. The owner or operator must notify 

the Director at least 60 days before plugging of a well. At this time, if any 

changes have been made to the original well plugging plan, the owner or operator 

must also provide the revised well plugging plan. At the discretion of the 

Director, a shorter notice period may be allowed. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the commenter’s support; the final rule retains this 

provision. 

Letter ID: 0259 Comment ID: 24939 Letter Lines: 2815 to 2830 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

106
Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: Rule Provision: 146.92(d) 

EPA Proposal: (d) Plugging report. Within 60 days after plugging or at the time 

of the next semi-annual report (whichever occurs earlier) the owner or operator 

must submit a plugging report to the Director. If the semi-annual report is due 

less than 15 days after completion of plugging, then the report must be 

submitted within 60 days after plugging. The report must be certified as 

accurate by the owner or operator and by the person who performed the plugging 

operation (if other than the owner or operator.) 

GWPC Recommendations: (d) Plugging report. Within 60 days after plugging the 

owner or operator must submit a plugging report to the Director. The report 

must be certified as accurate by the owner or operator and by the person who 

performed the plugging operation (if other than the owner or operator.) 

Rationale: Simplification 

Individual Response: EPA has revised the text at §146.92(d) to reduce confusion. The final rule 

text reads, "Within 60 days after plugging the owner or operator must submit a plugging report to 

the Director." 

Letter ID: 0259 Comment ID: 24940 Letter Lines: 2832 to 2846 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

Comment: Rule Provision: 146.93 

EPA Proposal: 13. Post-injection site care and site closure 

(a) The owner or operator of a Class VI well must prepare, maintain, and comply 

with a plan for post-injection site care and site closure that meets the 

requirements of paragraph (a)(2) of this section and is acceptable to the 

Director. 

(1) The owner or operator must submit the post-injection site care and site 

closure plan as a part of the permit application to be approved by the Director. 

GWPC Recommendations: Support the proposed EPA language 

Rationale: Agree with EPA’s rationale 

107
Individual Response: EPA acknowledges the commenter’s support; the final rule retains this 

provision. 

Letter ID: 0259 Comment ID: 24941 Letter Lines: 2848 to 2859 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment: EPA Proposal: (2) The post-injection site care and site closure plan must 

include the following information: 

(i) The pressure differential between pre-injection and predicted post-injection 

pressures in the injection zone; 

(ii) The predicted position of the carbon dioxide plume and associated pressure 

front at site closure as demonstrated in the area of review evaluation required 

under § 146.84(b); 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the commenter’s support; the final rule retains this 

provision. 

Letter ID: 0259 Comment ID: 24942 Letter Lines: 2861 to 2870 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5220 2.8.2.1 Post-injection monitoring activities 

Comment: Rule Provision: 146.93(a)(2) 

(iii) A description of post-injection monitoring location, methods, and proposed 

frequency; and 

(iv) A proposed schedule for submitting post-injection site care monitoring 

results to the Director. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the commenter’s support; the final rule retains this 

provision. 

108
Letter ID: 0259 Comment ID: 24943 Letter Lines: 2872 to 2879 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment: EPA Proposal: (3) Upon cessation of injection, owners or operators of Class VI 

wells must either submit an amended post-injection site care and site closure 

plan or demonstrate to the Director through monitoring data and modeling results 

that no amendment to the plan is needed. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the commenter’s support; the final rule retains this 

provision. 

Letter ID: 0259 Comment ID: 24944 Letter Lines: 2881 to 2887 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment: EPA Proposal: (4) The owner or operator may modify and resubmit the postinjection site care and site closure plan for the Director’s approval within 30 

days of such change. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the commenter’s support; the final rule retains this 

provision. 

Letter ID: 0259 Comment ID: 24945 Letter Lines: 2889 to 2917 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations 

Comment: Rule Provision: 146.93(b) 

EPA Proposal: (b) The owner or operator shall monitor the site following the 

cessation of injection to show the position of the carbon dioxide plume and 

pressure front and demonstrate that USDWs are not being endangered. 

109
(1) The owner or operator shall continue to conduct monitoring as specified in 

the Director-approved post-injection site care and site closure plan for at 

least 50 years following the cessation of injection. At the Director’s 

discretion, the monitoring will continue until the geologic sequestration 

project no longer poses an endangerment to USDWs. 

GWPC Recommendations: (b) The owner or operator shall monitor the site following 

the cessation of injection. 

(1) The owner or operator shall continue to conduct monitoring as specified in 

the Director-approved post-injection site care and site closure plan until 

closure is authorized pursuant to 146.93(b)(3). 

Rationale: Eliminate the 50 year requirement. 

There is no justification for extending completed projects for the presumptive 

50 years, and it will be difficult to accept much shorter demonstration periods 

with the 50 year presumption in the regulations. Default 50-year period defeats 

incentives for best site identification and best MMV 

Need for site-specific considerations and use of data 

Need achievable and definable standard 

Individual Response: EPA agrees that there will be circumstances where it can be demonstrated 

in less than 50 years that the plume and pressure front no longer pose a risk of endangerment to 

USDWs. For this reason, the final GS regulation includes a provision that the Director may, at 

his or her discretion, shorten the post-injection site care timeframe if the owner or operator can 

demonstrate that the GS project does not pose an endangerment to USDWs, as specified in 

§146.93(b)(2). Such a demonstration will be site-specific, and based on pressure monitoring and 

USDW impacts. Alternatively, the final rule at §146.93(c), also allows the Director to approve an 

alternative post-injection site care timeframe where an owner or operator can demonstrate during 

the permitting process that an alternative post-injection site care timeframe, other than the 50 

year default, is appropriate and ensures non-endangerment of USDWs. The demonstration must 

be based on site-specific information, including the results of site-specific computational 

modeling; the predicted timeframe for pressure decline; the predicted rate of carbon dioxide 

plume migration; site-specific chemical processes that will result in carbon dioxide trapping; the 

predicted rate of carbon dioxide trapping; characterization of the confining zone(s); laboratory 

analyses or studies to verify the information on trapping; the presence of potential conduits for 

fluid movement and the quality of abandoned well plugs within the AoR; the distance between 

the injection zone and the USDWs above and/or below the injection zone; and any additional 

site-specific factors determined by the Director. The demonstration must meet the criteria at 

§146.93(c)(2) for ensuring the quality and accuracy of the data and models on which the 

demonstration is based. This demonstration would be submitted as part of the permit application, 

per §146.82(a)(18), in addition to the PISC and site closure plan required at §146.82(a)(17). 

110
EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in all but a limited number of cases. This default 50 

year post-injection site care timeframe represents a reasonable and protective monitoring period 

based on a review of research studies, industry reports, and existing environmental programs, 

and evaluation of public comments. 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

Letter ID: 0259 Comment ID: 24946 Letter Lines: 2919 to 2932 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: Rule Provision: 146.93(b) 

EPA Proposal: (2) If the owner or operator can demonstrate to the satisfaction 

of the Director before 50 years, based on monitoring and other site-specific 

data, that the geologic sequestration project no longer poses an endangerment to 

USDWs, the Director may approve an amendment to the post-injection site care and 

site closure plan to reduce the frequency of monitoring or may authorize site 

closure before the end of the 50-year period. 

GWPC Recommendations: (2) The owner or operator can request and demonstrate to 

the satisfaction of the Director that the post-injection site care and site 

closure plan should be revised to reduce the frequency of monitoring. 

Rationale: See above regarding elimination of 50-year presumptive time period. 

Individual Response: As described above, EPA disagrees that a post-injection site care 

timeframe of 50 years is excessive for most Class VI wells. However, EPA agrees that there will 

be circumstances where it can be demonstrated in less than 50 years that the plume and pressure 

front no longer pose a risk of endangerment to USDWs. For this reason, the GS rule offers 

owners or operators flexibility regarding the duration of the PISC timeframe by: (1) allowing the 

Director discretion to shorten or lengthen the PISC timeframe during the post-injection period 

based on site-specific data, pursuant to requirements at §146.93(b); or (2) affording the Director 

discretion to allow a Class VI well owner or operator to demonstrate, during the permitting 

process based on substantial data, that an alternative PISC timeframe may be appropriate if it 

ensures non-endangerment of USDWs pursuant to requirements at §146.93(c). 

111
EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

Letter ID: 0259 Comment ID: 24947 Letter Lines: 2934 to 2959 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations 

Comment: EPA Proposal: (3) Prior to authorization for site closure, the owner or operator 

must submit to the Director a demonstration, based on monitoring and other sitespecific data, that the carbon dioxide plume and pressure front have stabilized 

and that no additional monitoring is needed to assure that the geologic 

sequestration project does not pose an endangerment to USDWs. 

GWPC Recommendations: (3) Prior to authorization for site closure, the owner or 

operator must demonstrate to the Director, based on monitoring, other sitespecific data, and modeling that is reasonably consistent with site performance, 

that no additional monitoring is needed to assure that the geologic 

sequestration project does not and is not expected to pose an endangerment to 

USDWs. The Director shall approve closure if the owner or operator demonstrates, 

based on the current understanding of the site, including monitoring data and/or 

modeling, all of the following: (i) the estimated magnitude and extent of the 

project footprint (CO2 plume and the area of elevated pressure) ; (ii) the 

estimated location of the detectable CO2 plume; (iii) that there is no 

significant leakage of either CO2 or displaced formation fluids that is 

endangering USDWs; (iv) that the injected or displaced fluids are not expected 

to migrate in the future in a manner that encounters a potential leakage pathway 

into a USDW; (v) that the injection wells at the site completed into or through 

the injection zone or confining zone are plugged and abandoned in accordance 

with these requirements; and (vi) any remaining project monitoring wells at the 

site are being managed by a person and in a manner acceptable to the Director. 

Rationale: The GWPC revised this section to establish the performance based 

criteria for selecting the monitoring period. 

Individual Response: EPA disagrees that the rule should specify the criteria for setting the 

monitoring timeframe. Instead, EPA believes that such determinations are site-specific and 

should be described in a project specific post-injection site care and site closure plan. EPA also 

believes that periodic reviews and updates, where necessary, to the plan are important to 

112
ensuring that the site continues to be managed effectively and to determine whether shortening 

the monitoring timeframe is appropriate. 

As described above, EPA agrees that there will be circumstances where it can be demonstrated in 

less than 50 years that the plume and pressure front no longer pose a risk of endangerment to 

USDWs. For this reason, the GS rule offers owners or operators flexibility regarding the duration 

of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC 

timeframe during the post-injection period based on site-specific data, pursuant to requirements 

at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator 

to demonstrate, during the permitting process based on substantial data, that an alternative PISC 

timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to 

requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

Letter ID: 0259 Comment ID: 24948 Letter Lines: 2961 to 2968 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: EPA Proposal: (4) If such a demonstration cannot be made (i.e., if the carbon 

dioxide plume and pressure front have not stabilized) after the 50-year period, 

the owner or operator must submit to the Director a plan to continue postinjection site care. 

GWPC Recommendations: Delete 

Rationale: No longer necessary if 50 year time period is removed. 

Individual Response: As described above, EPA believes that, to ensure USDW protection from 

endangerment, a default timeframe for post-injection site care is necessary in most cases. A 50 

year post-injection site care timeframe represents a reasonable and protective monitoring period 

for most GS sites based on a review of research studies, industry reports, and existing 

environmental programs, and evaluation of public comments. 

EPA believes that a 50-year default post-injection site care timeframe, as required at 

§146.93(b)(1), is not overly burdensome, does not exaggerate the risks associated with GS, is 

113
consistent with other environmental programs, and sufficiently protects USDWs from 

endangerment. 

Letter ID: 0259 Comment ID: 24949 Letter Lines: 2970 to 2980 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

Comment: Rule Provision: 146.93(c) 

EPA Proposal: (c) Notice of intent for site closure. The owner or operator must 

notify the Director at least 120 days before site closure. At this time, if any 

changes have been made to the original post-injection site care and site closure 

plan, the owner or operator must also provide the revised plan. At the 

discretion of the Director, a shorter notice period may be allowed. 

GWPC Recommendations: No recommendation 

Rationale: Need for site-specific considerations and use of data 

Individual Response: EPA acknowledges the comment. For additional information on EPA's 

final regulatory approach, please see the final rule and preamble as well as the rulemaking 

docket. 

Letter ID: 0259 Comment ID: 24950 Letter Lines: 2982 to 2990 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

Comment: Rule Provision: 146.93(d) 

EPA Proposal: (d) After the Director has authorized site closure, the owner or 

operator must plug all monitoring wells in a manner which will not allow 

movement of injection or formation fluids that endangers a USDW. 

GWPC Recommendations: No recommendation 

Rationale: Need for site-specific considerations and use of data 

Individual Response: EPA acknowledges the comment. For additional information on EPA's 

final regulatory approach, please see the final rule and preamble as well as the rulemaking 

docket. 

114
Letter ID: 0259 Comment ID: 24951 Letter Lines: 2992 to 3018 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

Comment: EPA Proposal: (e) Once the Director has authorized site closure, the owner or 

operator must submit a site closure report within 90 days that must thereafter 

be retained at a location designated by the Director. The report must include: 

(1) Documentation of appropriate injection and monitoring well plugging as 

specified in § 146.92 and paragraph (c) of this section. The owner or operator 

must provide a copy of a survey plat which has been submitted to the local 

zoning authority designated by the Director. The plat must indicate the 

location of the injection well relative to permanently surveyed benchmarks. The 

owner or operator must also submit a copy of the plat to the Regional 

Administrator of the appropriate EPA Regional Office; 

GWPC Recommendations: (e) Once the Director has authorized site closure, the 

owner or operator must submit a site closure report within 90 days after 

completion of all closure operations. The report must include: 

(1) Documentation of appropriate injection and monitoring well plugging as 

specified in §146.92 and paragraph (c) of this section. The owner or operator 

must provide a copy of a survey plat which has been submitted to the local 

zoning authority designated by the Director. The plat must indicate the location 

of the injection well(s) relative to permanently surveyed benchmarks. The owner 

or operator must also submit a copy of the plat to the Regional Administrator of 

the appropriate EPA Regional Office; 

Rationale: What is the retention period? Many other programs have a three year 

limit for retention of records. EPA is the steward of information at this point 

of the project, not the owner or operator. 

Individual Response: The GS regulation at §146.93(g) requires the owner or operator to record 

a notation on the deed to the facility property or other similar document examined during a title 

search that the land has been used to sequester CO2 on the deed to the facility property at the 

time of site closure. 

Regarding record retention, EPA has clarified the recordkeeping requirements in the final GS 

rule, which includes requirements that well plugging reports, as required at §146.92(d), postinjection site care data, as required at §146.93(f), and site closure reports, as required at 

§146.93(h), must be kept by the owner or operator for ten years after site closure. EPA believes 

that longer record retention times for GS wells are appropriate and necessary for the postinjection and site closure period to ensure that data are available to support non-endangerment 

115
demonstrations and to address any concerns that may arise following site closure. This data will 

also support EPA's review of project data as part of the adaptive rulemaking approach. 

Letter ID: 0259 Comment ID: 24952 Letter Lines: 3020 to 3031 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

Comment: EPA Proposal: (2) Documentation of appropriate notification and information to 

such State, local and tribal authorities as have authority over drilling 

activities to enable such State and local authorities to impose appropriate 

conditions on subsequent drilling activities that may penetrate the injection 

and confining zone(s); and 

(3) Records reflecting the nature, composition and volume of the carbon dioxide 

stream. 

GWPC Recommendations: No recommendation 

Rationale: Need for site-specific considerations and use of data 

Individual Response: The GS regulation at §146.93(g) requires the owner or operator to record 

a notation on the deed to the facility property or other similar document examined during a title 

search that the land has been used to sequester CO2 on the deed to the facility property at the 

time of site closure. 

Letter ID: 0259 Comment ID: 24953 Letter Lines: 3033 to 3047 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

Comment: Rule Provision: 146.93 

EPA Proposal: (f) Each owner or operator of a Class VI injection well must 

record a notation on the deed to the facility property or any other document 

that is normally examined during title search that will in perpetuity provide 

any potential purchaser of the property the following information: 

(1) The fact that land has been used to sequester carbon dioxide; 

(2) The name of the State agency, local authority, and/or tribe with which the 

survey plat was filed, as well as the address of the Regional Environmental 

Protection Agency Office to which it was submitted; and 

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GWPC Recommendations: No recommendation 

Rationale: Need for site-specific considerations and use of data 

Individual Response: The GS regulation at §146.93(g) requires the owner or operator to record 

a notation on the deed to the facility property or other similar document examined during a title 

search that the land has been used to sequester CO2 on the deed to the facility property at the 

time of site closure. 

Letter ID: 0259 Comment ID: 24954 Letter Lines: 3049 to 3060 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

Comment: EPA Proposal: (3) The volume of fluid injected, the injection zone or zones into 

which it was injected, and the period over which injection occurred. 

(g) The owner or operator must retain for three years following site closure, 

records collected during the post-injection site care period. The owner or 

operator must deliver the records to the Director at the conclusion of the 

retention period, and the records must thereafter be retained at a location 

designated by the Director for that purpose. 

GWPC Recommendations: No recommendation 

Rationale: Need for site-specific considerations and use of data 

Individual Response: The GS regulation at §146.93(g) requires the owner or operator to record 

a notation on the deed to the facility property or other similar document examined during a title 

search that the land has been used to sequester CO2 on the deed to the facility property at the 

time of site closure. 

Letter ID: 0259 Comment ID: 24956 Letter Lines: 3072 to 3098 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5800 2.13 Comments on emergency and remedial response (40 CFR 146.94) 

Comment: Rule Provision: 146.94(b) 

(b) If the owner or operator obtains evidence that the injected carbon dioxide 

stream and associated pressure front may cause an endangerment to a USDW, the 

owner or operator must: 

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(1) Immediately cease injection; 

(2) Take all steps reasonably necessary to identify and characterize any 

release; 

(3) Notify the Director within 24 hours; and 

(4) Implement the emergency and remedial response plan approved by the Director. 

GWPC Recommendations: (b) If the owner or operator obtains evidence that the 

injected carbon dioxide stream, displaced formation fluids or associated 

pressure front endangers a USDW, the owner or operator must: 

(1) Immediately cease injection; 

(2) Take all steps reasonably necessary to identify and characterize the 

endangerment posed; 

(3) Notify the Director or the designated representative within 24 hours of 

becoming aware of the endangerment; and 

(4) Implement the emergency and remedial response plan approved by the Director. 

Rationale: The GWPC felt the notification period needed clarification since it 

did not specify when the clock began to run for the 24 hour notice period. 

Further, it was felt that notification of someone representing the Director 

would also constitute appropriate notice. 

Individual Response: After consideration of comments, EPA has finalized the rule language in 

§146.94(b) as proposed. In the introductory section of §146.94(b), EPA clarifies that the pressure 

front, as defined in §146.81, is a zone where the pressure differential is sufficient to cause the 

movement of injected fluids or formation fluids into a USDW. Therefore, displaced formation 

fluids are implicitly included in the requirements for §146.94. EPA also clarifies that owners or 

operators must take action when the CO2 stream or pressure front may cause endangerment. In 

order to prevent the endangerment of USDWs, as required under §1421 of the SDWA, EPA 

expects the owner or operator to act preemptively and not wait until endangerment has occurred. 

This language is consistent with existing UIC requirements for other well classes and EPA’s 

authority under the SDWA. 

Regarding changes to the language in §146.94(b)(1), EPA clarifies that the Agency expects that 

owners or operators take care not to damage the well when ceasing injection under 

§146.94(b)(1). At §146.94(b)(2), EPA is maintaining the requirement to “characterize the 

release.” In order to prevent the endangerment of USDWs, as required under §1421 of the 

SDWA, EPA expects the owner or operator to act preemptively and not wait until endangerment 

has occurred. This language is consistent with existing UIC requirements for other well classes 

and EPA’s authority under the SDWA. 

Concerning commenters’ suggestions for §146.94(b)(3), EPA clarifies that the 24 hours begins 

when the owner or operator obtains evidence of possible endangerment. Note that the definition 

of the Director in 40 CFR 144.3 includes the Director’s authorized representative. EPA believes 

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the rule language is clear on this requirement. 

Letter ID: 0259 Comment ID: 24957 Letter Lines: 3100 to 3113 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5800 2.13 Comments on emergency and remedial response (40 CFR 146.94) 

Comment: EPA Proposal: (c) The Director may allow the operator to resume injection prior 

to remediation if the owner or operator demonstrates that the injection 

operation will not endanger USDWs. 

(d) The owner or operator must notify the Director and obtain his approval prior 

to conducting any well workover. 

GWPC Recommendations: Support the proposed EPA language for (c) 

(d) The owner or operator must notify the Director prior to conducting any well 

workover in response to any case of endangerment. 

Rationale: In critical situations, time spent obtaining approval could adversely 

affect the ability to conduct operations or increase the level of endangerment. 

Individual Response: Since proposal, EPA has modified the final regulatory language at 

§146.94(d) to clarify what constitutes a workover to address a well failure (which invokes 

remedial actions) and what constitutes a maintenance-type workover. For maintenance-type 

workovers (i.e., those that are scheduled in advance), the owner or operator must notify and gain 

approval from the Director prior to beginning the workover. In the final GS regulation, EPA has 

moved this requirement to the reporting requirements at §146.91(d) to clarify its intent. 

Regarding concerns that notification could delay responses, EPA clarifies that the GS rule, at 

§146.94(b), describes procedures owners or operators must take in emergency situations. 

Specifically, upon determining that there is a problem with the well that may endanger a USDW, 

the owner or operator must first cease injection, then take all steps reasonably necessary to 

identify and characterize any release, notify the Director, and implement the approved 

emergency and remedial response plan, which may include a well workover. EPA believes that 

ceasing injection (which the owner or operator would do immediately and before notifying the 

Director) is the action necessary to prevent or mitigate endangerment of USDWs as required 

under the SDWA. 

Letter ID: 0259 Comment ID: 24964 Letter Lines: 798 to 815 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

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Comment: Rule Provision: 144.80 

EPA Proposal: 11. Section 144.80 is amended by revising the first sentence in 

paragraph (e) and by adding paragraph (f)to read as follows: 

§ 144.80 What is a Class V injection well? * * * * * 

(e) Class V. Injection wells not included in Class I, II, III, IV or VI. * * 

* 

(f) Class VI. Wells used for geologic sequestration of carbon dioxide. 

GWPC Recommendations: (4) For enhanced recovery of oil or natural gas where 

geologic sequestration is occurring during or in connection with enhanced 

recovery of oil or natural gas provided (i) there is reasonable expectation of 

more than insignificant future production volumes or rates as a result of carbon 

dioxide injection and (ii) operating pressures are no higher than reasonably 

necessary to produce such volumes or rates; 

Individual Response: EPA disagrees with the suggested changes to the rule language; geologic 

sequestration conducted as part of enhanced recovery operations is considered Class II. Injection 

where geologic sequestration is the primary purpose is categorized as Class VI. 

Letter ID: 0259 Comment ID: 24965 Letter Lines: 917 to 925 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment: Rule Provision: 146.81 Applicability. 

EPA Proposal: (a) This subpart establishes criteria and standards for 

underground injection control programs to regulate Class VI carbon dioxide 

geologic sequestration injection wells. 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment. For additional information on EPA's 

final regulatory approach, please see the final rule and preamble as well as the rulemaking 

docket. 

Letter ID: 0259 Comment ID: 24966 Letter Lines: 456 to 471 

Comment Code: 5600 2.11 Comments related to UIC Program primacy for Class VI wells 

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Comment: EPA Notice Questions: 73 FR 43523 

EPA Rule Issue: 48. To gain authority for Class VI wells, States, Territories, 

and Tribes will be required to show that their regulations are at least as 

stringent as, and may be more stringent than, the proposed minimum Federal 

requirements (e.g., inspection, operation, monitoring, and recordkeeping 

requirements that well owners or operators must meet). Such Primacy States, 

Territories, and Tribes are authorized under Section 1422 of the SDWA. EPA 

Notice 43523. 

GWPC CO2 Committee Response: Retain current requirement, but recognize that 

geology varies from state to state and some modifications may be appropriate 

that will result in variations that are not less stringent, but simply adapted 

to different circumstances. There should also be some recognition that the 

beneficial effects of GS may be enhanced by allowing flexibility for adaptation 

of state requirements. 

Individual Response: EPA agrees that it is important to balance flexibility and national 

consistency. The GS rule sets forth minimum requirements, tailored to the unique nature of CO2 

GS, which must be met in order to ensure USDW protection from endangerment. EPA 

acknowledges the importance of flexibility for certain Class VI well requirements given the 

variety of geologic settings in which GS will be applied and therefore affords the Director 

discretion when making permitting decisions. Such requirements where the Director has 

discretion include whether to require owners or operators to identify and characterize additional 

confining zones, as specified in §146.83, whether to require surface air monitoring and/or soil 

gas monitoring, as specified in §146.90, and whether to extend or shorten the post-injection site 

care period or approve an alternative post-injection site care timeframe as part of the permitting 

process, as specified in §146.93. The GS rule balances the need for site-specific decisions with 

the need for minimum standards to ensure national consistency and USDW protection from 

endangerment while also ensuring that states have the data they need to make permitting 

decisions. EPA Headquarters also plans to review initial permits to ensure that the final rule, 

including all permitting decisions, are implemented consistently, and to ensure that USDW 

protection goals are consistently met across differing geologic situations. 

Letter ID: 0259 Comment ID: 29176 Letter Lines: 2044 to 2081 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87 

EPA Proposal: 7. Logging, sampling, and testing prior to injection well 

operation 

(a) During the drilling and construction of a Class VI injection well, the owner 

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or operator must run appropriate logs, surveys and tests to determine or verify 

the depth, thickness, porosity, permeability, and lithology of, and the salinity 

of any formation fluids in, all relevant geologic formations to assure 

conformance with the injection well construction requirements under § 146.86, 

and to establish accurate baseline data against which future measurements may be 

compared. The owner or operator must submit to the Director a descriptive 

report prepared by a knowledgeable log analyst that includes an interpretation 

of the results of such logs and tests. At a minimum, such logs and tests must 

include: 

GWPC Recommendations: (a) During the drilling and construction of a Class VI 

injection well, the owner or operator must run appropriate logs, surveys and 

tests to determine or verify the depth, thickness, porosity, permeability, and 

lithology of, and the salinity of any formation fluids in, all relevant geologic 

formations to assure conformance with the injection well construction 

requirements under §146.86, and to establish accurate baseline data against 

which future measurements may be compared. The owner or operator must submit to 

the Director a descriptive report prepared by a knowledgeable log analyst that 

includes an interpretation of the results of such logs and tests. The Director 

may require such logs and tests as may be needed after taking into account the 

availability of similar data in the area of the drilling site, the construction 

plan, and the need for additional information that may arise from time to time 

as the construction of the well progresses and these may include the following: 

Rationale: In well defined areas, these evaluations are frequently unnecessary. 

The director should have discretion to select the appropriate requirements 

necessary to ensure sufficient baseline data and information are available. For 

example, in an area where a number of wells are being drilled, the logging of 

surface hole yields little useful additional information. 

In particular, this change would allow the Director to reduce the requirements 

when multiple wells are installed for a project. 

Individual Response: EPA believes that the logging and testing requirements in the GS rule are 

appropriate and necessary. The requirements at §146.87 stem from existing knowledge and 

practices in place for other injection well classes and within the oil and gas industry, and are 

tailored to the special characteristics of CO2 injection for GS. 

EPA is developing guidance on monitoring and testing that will describe recommended tests and 

procedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website 

at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA clarifies that §146.87(b) provides some flexibility. EPA notes that §146.87(b) allows 

information on cores from nearby wells to be submitted if the owner or operator can demonstrate 

that core retrieval is not possible and that cores from nearby wells are representative of 

122
conditions at the GS well. EPA clarifies that, at a minimum, reports on cores of injection zones 

and confining zones, and samples of formation fluids must be submitted. Section 146.87(b) gives 

the Director authority to require the owner or operator to core other formations in the borehole if 

necessary to provide sufficient geologic information to verify that the site is suitable for GS. 

Letter ID: 0259 Comment ID: 29177 Letter Lines: 2083 to 2091 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: EPA Proposal: (1) Deviation checks during drilling on all holes constructed by 

drilling a pilot hole which are enlarged by reaming or another method. Such 

checks must be at sufficiently frequent intervals to determine the location of 

the borehole and to assure that vertical avenues for fluid movement in the form 

of diverging holes are not created during drilling; and 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment; the final rule retains the requirements 

for deviation checks required at §146.87(a)(1). EPA adds that the Director would have discretion 

to approve a plan without deviation checks that addresses circumstances where these tests may 

not be practical or useful, such as those mentioned by the commenter. EPA encourages owners 

or operators to discuss these situations with the Director when planning the deviation testing. 

Letter ID: 0259 Comment ID: 29178 Letter Lines: 2093 to 2099 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(a) 

EPA Proposal: (2) Before and upon installation of the surface casing: 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment; the final rule retains the requirements 

for logging and testing prior to and upon installation of surface casing. 

Letter ID: 0259 Comment ID: 29179 Letter Lines: 2101 to 2111 

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Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: EPA Proposal: (i) Resistivity, spontaneous potential, and caliper logs before 

the casing is installed; and 

GWPC Recommendations: (i) Resistivity, spontaneous potential, and caliper logs 

before the casing is installed; and 

Rationale: After a few wells are drilled in an area, these evaluations are 

frequently unnecessary and yield little new information.This is an example of 

why it is appropriate to make this a discretionary rather than mandatory 

requirement. The proposed revision to 146.87(a) would give the Director the 

necessary discretion. 

Individual Response: EPA disagrees that the requirements for logs, surveys, and tests are 

excessive or duplicative. All logs, surveys, and tests listed at §146.87(a) are necessary to verify 

information about the injection and confining zones and ensure that the well is being drilled and 

cased as approved, and has mechanical integrity. EPA notes that the Director has the discretion 

at §146.87(a)(5) to approve alternative methods that provide equivalent or better information. 

Letter ID: 0259 Comment ID: 29180 Letter Lines: 2113 to 2122 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: EPA Proposal: (ii) A cement bond and variable density log, and a temperature log 

after the casing is set and cemented. 

GWPC Recommendations: (ii) A cement bond and variable density log, and a 

temperature log after the casing is set and cemented. 

Rationale: Unusual to run these logs in a surface hole due to uniformity of 

shallow geology. This is an example of why it is appropriate to make this a 

discretionary rather than mandatory requirement. The proposed revision to 

146.87(a) would give the Director the necessary discretion. 

Individual Response: As described above, EPA disagrees that the requirements for logs, 

surveys, and tests are excessive or duplicative. All logs, surveys, and tests listed at §146.87(a) 

are necessary to verify information about the injection and confining zones and ensure that the 

well is being drilled and cased as approved, and has mechanical integrity. EPA notes that the 

Director has the discretion at §146.87(a)(5) to approve alternative methods that provide 

equivalent or better information. 

EPA clarifies that in the final GS rule, §146.87(a)(2)(ii) reads as follows: "A cement bond and 

variable density log to evaluate cement quality radially, and a temperature log after the casing is 

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set and cemented." 

Letter ID: 0259 Comment ID: 29181 Letter Lines: 2124 to 2128 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: EPA Proposal: (3) Before and upon installation of the long string casing: 

GWPC Recommendations: Support the proposed EPA language. 

Rationale: Agree with EPA’s rationale. 

Individual Response: EPA acknowledges the comment; the final rule retains the requirements 

for logging and testing prior to and upon installation of the long string casing. 

Letter ID: 0259 Comment ID: 29182 Letter Lines: 2130 to 2134 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: EPA Proposal: (i) Resistivity, spontaneous potential, porosity, caliper, gamma 

ray, fracture finder logs, and any other logs the Director requires for the 

given geology before the casing is installed; and 

GWPC Recommendations: Support the proposed EPA language. 

Individual Response: EPA acknowledges the comment; the final rule retains the requirements 

for the logs and tests required at §146.87(a)(3). 

Letter ID: 0259 Comment ID: 29183 Letter Lines: 2136 to 2146 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: EPA Proposal: (ii) A cement bond and variable density log, and a temperature log 

after the casing is set and cemented. 

GWPC Recommendations: (ii) Cement evaluation logs after the casing is set and 

cemented to evaluate cement quality with sufficient radial resolution to 

identify channels or missing cement. 

Rationale: Acceptable to specify basic logging requirements, however, special 

125
logs should not be specified. Any other information from the area should be 

drawn on. Provides more flexibility to select the appropriate log to demonstrate 

adequate cement bond. 

Individual Response: EPA agrees with the suggested change. In the final GS rule, 

§146.87(a)(2)(ii) reads as follows: "A cement bond and variable density log to evaluate cement 

quality radially, and a temperature log after the casing is set and cemented." 

EPA believes that a minimum suite of logs and tests is necessary at all GS wells. All logs, 

surveys, and tests listed at §146.87(a) are necessary to verify information about the injection and 

confining zones and ensure that the well is being drilled and cased as approved and has 

mechanical integrity. EPA adds that, should alternative methods be shown to provide equivalent 

or better information or if site-specific conditions and risk factors dictate that other logs are 

necessary, the Director has the discretion at §146.87(a)(5) to require further logs and tests if 

necessary and to approve alternative methods that provide equivalent or better information. 

Letter ID: 0259 Comment ID: 29184 Letter Lines: 2148 to 2175 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: EPA Proposal: 146.87(a)(4) 

(4) A series of tests designed to demonstrate the internal and external 

mechanical integrity of injection wells, which may include: 

(i) A pressure test with liquid or gas; 

(ii) A tracer survey such as oxygen-activation logging; 

(iii) A temperature or noise log; 

(iv) A casing inspection log, if required by the Director; and 

(5) Any alternative methods that provide equivalent or better information and 

that are required of and/or approved of by the Director. 

GWPC Recommendations: (4) Test(s) designed to demonstrate the internal and 

external mechanical integrity of injection wells, which may include: 

(i) A pressure test with liquid or gas; 

(ii) Diagnostic tools such as oxygen-activation logging; 

(iii) A temperature or noise log; and 

(iv) A casing inspection log. 

(5) Accept the EPA language and numbering. 

Rationale: Technical and grammatical corrections 

126
In (iv), "if required by the Director" is unnecessary. 

We interpret that (5) applies to 146.87(a) 

Individual Response: EPA agrees with the commenter about the wording of the casing 

inspection log requirement at §146.87(a)(4) and made the suggested change to improve clarity. 

In the final regulation, §146.87(a)(4)(iv) does not include the phrase, “if required by the 

Director.” 

Letter ID: 0259 Comment ID: 29185 Letter Lines: 2177 to 2195 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule provision: 146.87(b) 

EPA Proposal: (b) The owner or operator must take and submit to the Director 

whole cores or sidewall cores of the injection zone and confining system and 

formation fluid samples from the injection zone(s). The Director may accept 

cores from nearby wells if the owner or operator can demonstrate that core 

retrieval is not possible and that such cores are representative of conditions 

at the well. The Director may require the owner or operator to core other 

formations in the borehole. 

GWPC Recommendations: (b) The owner or operator must submit to the Director a 

report describing whole cores or sidewall cores representative of the injection 

zone and confining system and formation fluid samples from the injection 

zone(s). The Director may accept data from cores and fluid samples from nearby 

wells if the owner or operator can demonstrate that such data are representative 

of conditions in the wellbore. 

Rationale: The information required should be sufficient to properly describe 

the injection and confining zones. 

Individual Response: EPA clarifies that it is not the Agency's intent that physical cores be 

submitted to the Director. In the final GS rule, EPA has revised the first sentence of §146.87(b) 

to read as follows: "The owner or operator must take whole cores or sidewall cores of the 

injection zone and confining system and formation fluid samples from the injection zone(s), and 

must submit to the Director a detailed report prepared by a log analyst that includes: well log 

analyses (including well logs), core analyses, and formation fluid sample information...." 

EPA believes that logs and tests must be performed on each well drilled regardless of existing 

information about the area to account for the complexity of CO2 injection well construction and 

the buoyancy of CO2. Existing lithologic and geologic information may lack the details needed 

127
for site-specific well design and the geology needed to support protection of USDWs from 

endangerment. 

Letter ID: 0259 Comment ID: 29186 Letter Lines: 2197 to 2206 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: EPA Proposal: (c) The owner or operator must record the fluid temperature, pH, 

conductivity, reservoir pressure and the static fluid level of the injection 

zone(s). 

GWPC Recommendations: (c) Prior to injection well operation, the owner or 

operator must record the formation temperature, formation fluid pH and 

conductivity, and reservoir pressure of the injection zone(s). 

Rationale: Technical corrections. Reservoir pressure and static fluid level are 

redundant parameters. 

Individual Response: EPA disagrees that "reservoir pressure" and "static fluid level" are 

redundant parameters. Although the static fluid level is equal to the bottom hole pressure, this 

may not always be identical to the reservoir pressure. Additionally, measuring the static fluid 

level provides additional assurance that the reading is accurate (or, provides the needed 

information in cases where a good reading is not obtained). In addition, a static fluid level 

measurement provides information regarding the proximity to USDWs that need protection 

afforded to them. 

Letter ID: 0259 Comment ID: 29187 Letter Lines: 2208 to 2224 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: EPA Proposal: (d) At a minimum, the owner or operator must determine or 

calculate the following information concerning the injection and confining 

zone(s): 

(1) Fracture pressure; 

(2) Other physical and chemical characteristics of the injection and confining 

zones; and 

(3) Physical and chemical characteristics of the formation fluids in the 

injection zone. 

GWPC Recommendations: Delete all 

Rationale: With the exception of calculating fracture pressure, the requirements 

128
of this section appear redundant to other requirements of prior sections. 

Recommend moving injection pressure to old (e), now renumbered as (d). 

(2) and (3) are also too vague. 

Individual Response: EPA believes that the requirement to provide information on the injection 

and confining zones in §146.87(d) is warranted, and that the rule provides flexibility to account 

for the variety of geologic conditions that may be encountered at GS sites. 

EPA is developing guidance on monitoring and testing that will describe recommended tests and 

procedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website 

at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 29188 Letter Lines: 2226 to 2249 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: EPA Proposal: (e) Upon completion, but prior to operation, the owner or operator 

must conduct the following tests to verify hydrogeologic characteristics of the 

injection zone: 

(1) A pump test; or 

(2) Injectivity tests. 

GWPC Recommendations: (d) At any time prior to injection well operation, the 

owner or operator must determine fracture pressures of the injection and 

confining zones and conduct tests to verify hydrogeologic and geomechanical 

characteristics of the injection zone, e.g., injectivity tests. 

Rationale: Allows the use of information such as leak off tests conducted during 

the drilling operation. 

Delete (1) 

It was felt that Geomechanical properties were at least as important as 

hydrogeologic characteristics. 

The results of a pump test (pumping fluid from the well) has no relevance for an 

injection well. 

If current (d) is deleted as recommended, this would become (d) 

Individual Response: EPA clarifies that the owner or operator has the option of using pump 

129
tests or injectivity tests depending on which would provide the most valuable information based 

on site-specific conditions. Further, EPA disagrees that pump tests are irrelevant to determining 

injection zone properties. Depending on the characteristics or depth of knowledge of the 

confining and injection zone formations, pump tests may be necessary to prove that no hydraulic 

connection exists between the injection zone and a USDW. 

EPA is developing guidance on monitoring and testing that will describe recommended tests and 

procedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website 

at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0259 Comment ID: 29189 Letter Lines: 2251 to 2268 

Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: Rule Provision: 146.87(f) 

EPA Proposal: (f) The owner or operator must provide the Director with the 

opportunity to witness all logging and testing by this subpart. The owner or 

operator must submit a schedule of such activities to the Director 30 days prior 

to conducting the first test and submit any changes to the schedule 30 days 

prior to the next scheduled test. 

GWPC Recommendations: (e) The owner or operator must provide the Director with 

the opportunity to witness all logging and testing by this subpart. The owner or 

operator must submit a schedule of such activities to the Director upon spudding 

the well and submit any changes to the schedule 48 hours prior to the scheduled 

test. 

Rationale: The changes reflect the realities of flexible rig schedules and are 

fully consistent with current Class II requirements and practices. 

If current (d) is deleted as recommended, this would become (e) 

Individual Response: EPA disagrees that the 30-day notification requirement is unreasonable. 

The 30-day notification mirrors the current requirement for logging and testing of new Class I 

wells, as described in §146.66. Acknowledging the developing nature of CO2 GS, EPA believes 

that involvement by the permitting authority in each project will provide much needed field data 

for assurance of USDW protection from endangerment and will help update and refine the 

permitting process. Adequate timing of notification will ensure the Director's ability to be 

involved. 

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